NUREG-1831

Safety Evaluation Report

Related to the License Renewal of

the Donald C. Cook Nuclear Plant,

Units 1 and 2

Docket Nos. 50-315 and 50-316

Indiana Michigan Power Company

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Washington, DC 20555-0001
v - I I I

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NUREG-1831

Safety Evaluation Report

Related to the License Renewal of

the Donald C. Cook Nuclear Plant,

Units 1 and 2

Docket Nos. 50-315 and 50-316

Indiana Michigan Power Company

Manuscript Completed: May 2005

Date Published: July 2005

Prepared by

J. G. Rowley

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 Donald C. Cook

Nuclear Plant (CNP), Units 1 and 2, license renewal application (LRA) by the U.S. Nuclear

Regulatory Commission (NRC) staff (the staff). By letter dated October 31, 2003, Indiana

Michigan Power Company (the applicant) submitted the LRA for CNP in accordance with Title

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

the Code of Federal Regulations (10 CFR Part 54 or the Rule). The applicant is requesting

renewal of the operating license for CNP Unit 1 (License No. DRP-58) and CNP Unit

2 (License No. DRP-74) for a period of 20 years beyond the current license expirations of

midnight, October 25, 2014 and December 23, 2017, respectively.

The CNP is located along the eastern shore of Lake Michigan in Lake Charter Township,

Berrien County, Michigan; approximately 11 miles south southwest of Benton Harbor, Michigan.

The nearest town is Bridgman, Michigan, which is approximately 2 miles south of the plant site.

Each unit employs a pressurized water reactor (PWR) nuclear steam supply system (NSSS)

furnished by Westinghouse Electric Corporation. The Unit 1 reactor is licensed for a power

output of 3304 megawatts-thermal (MWt), and the Unit 2 reactor is licensed for a power output

of 3468 MWt. The approximate net electrical outputs of Unit 1 and Unit 2 are 1080 megawattselectric (MWe) and 1155 MWe, respectively.

The staff reviewed the CNP license renewal application in accordance with Commission

regulations and NUREG-1800, "Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants," dated July 2001. The staff's conclusion of its review of

the CNP LRA can be found in Section 6 of this SER.

The NRC CNP license renewal project manager is Mr. Jonathan Rowley. Mr. Rowley may be

reached at 301-415-4053. Commenters should address written correspondence to the License

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

Washington, DC 20555-0001.

-iii-
TABLE OF CONTENTS

ABSTRACT ...................................... .iiiTABLE OF CONTENTS ....................................... vABBREVIATIONS ...................................... -xi1. 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 .............. 1-8

1.6 Summary of Confirmatory Items .......... ................ 1-12

1.7 Summary of Proposed License Conditions ............................ 1-13

2. STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2.1 Scoping and Screening Methodology .....................

2.1.1 Introduction .................................

2.1.2 Summary of Technical Information in the Application . .

2.1.2.1 Scoping Methodology ..................

2.1.2.2 Screening Methodology .................

2.1.3 Staff Evaluation ..............................

2.1.3.1 Scoping Methodology ..................

2.1.3.2 Screening Methodology .................

2.1.4 Evaluation Findings ..

2.2 Plant-Level Scoping Results ........................-

2.2.1 Summary of Technical Information in the Application . . 2.2.2 Staff Evaluation ..............................

2.2.3 Conclusion .......

2.3 System Scoping and Screening Results-Mechanical Systems .

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

....

....

....

....

....

....

....

....

....

....

....

....

....

....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

..2-1

..2-1

..2-1

..2-1

..2-1

..2-8

..2-9

.2-10

.2-34

.2-38

.2-38

.2-38

.2-38

.2-43

.2-43

........... 2-45

2.3.1.1 Reactor Vessel and'Control Rod Drive Mechanism Pressure

Boundary. ... .. 2-47

2.3.1.2 Reactor Vessel Internals ........ 2-49

2.3.1.3 Class 1 Piping,'Valves, and Reactor Coolant Pumps . 2-51

2.3.1.4 Pressurizer . 2-55

2.3.1.5 Steam Generators ....................-. ' .2-58

2.3.2 Engineered Safety Features ........................... 2-62 '. 

2.3.2.1 Containment Spray .2-62

2.3.2.2 Containment Isolation .2-64

2.3.2.3 Emergency Core Cooling . 2-65

2.3.2.4 Containment Equalization/Hydrogen Skimmer System .... 2-67
2.3.3 Auxiliary Systems .................. ...................... 2-68

2.3.3.1 Spent Fuel Pool ........ .......................... 2-68

2.3.3.2 Essential Service Water ........................... 2-73

2.3.3.3 Component Cooling Water ......................... 2-76

2.3.3.4 Compressed Air ................................. 2-82

2.3.3.5 Chemical and Volume Control ....................... 2-87

2.3.3.6 Heating, Ventilation, and Air Conditioning ..... ......... 2-88

2.3.3.7 Fire Protection .................................. 2-92

2.3.3.8 Emergency Diesel Generators ...................... 2-100

2.3.3.9 Security .......... ............................. 2-106

2.3.3.10 Post-Accident Containment Hydrogen Monitoring ...... 2-109

2.3.3.11 Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2) . 2-110

2.3.3.12 Miscellaneous Systems ......... .. ............... 2-119

2.3.4 Steam and Power Conversion Systems ......... ............. 2-121

2.3.4.1 Main Feedwater ................................. 2-121

2.3.4.2 Main Steam .................................... 2-125

2.3.4.3 Auxiliary Feedwater .............................. 2-130

2.3.4.4 Steam Generator Blowdown ....................... 2-133

2.3.4.5 Main Turbine ................................... 2-137

2.4 Scoping and Screening Results-Structures ........ .. ............... 2-138

2.4.1 Containment ......................... 2-145

2.4.1.1 Summary of Technical Information in the Application .... 2-145

2.4.1.2 Staff Evaluation ................................. 2-147

2.4.1.3 Conclusion ..................................... 2-157

2.4.2 Auxiliary Building ................. ...................... 2-157

2.4.2.1 Summary of Technical Information in the Application .... 2-157

2.4.2.2 Staff Evaluation ................................. 2-158

2.4.2.3 Conclusion ..................................... 2-158

2.4.3 Turbine Building and Screenhouse ......................... 2-158

2.4.3.1 Summary of Technical Information in the Application .... 2-158

2.4.3.2 Staff Evaluation ................................. 2-160

2.4.3.3 Conclusion ..................................... 2-167

2.4.4 Yard Structures .................. ...................... 2-168

2.4.4.1 Summary of Technical Information in the Application .... 2-168

2.4.4.2 Staff Evaluation ................................. 2-169

2.4.4.3 Conclusion ..................................... 2-169

2.4.5 Structural Commodities ............. .. ................... 2-169

2.4.5.1 Summary of Technical Information in the Application .... 2-169

2.4.5.2 Staff Evaluation ................................. 2-170

2.4.5.3 Conclusion ..................................... 2-171

2.5 Scoping and Screening Results-Electrical and Instrumentation and Controls

Systems ................................................... 2-171

2.5.0 Staff Evaluation Methodology .............................. 2-171

2.5.1 Summary of Technical Information in the Application .... ........ 2-172

2.5.2 Staff Evaluation ........................................ 2-172

2.5.3 Conclusion ............................................ 2-174

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

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

-vi-
3.0.1 Format of the Licence Renewal Application .......... ............. 3-2

3.0.1.1 Overview of Table1 ............. ..................... 3-2

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

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

3.0.2.1 Review of Aging Management Programs ...... .......... 3-4

3.0.2.2 Review of Aging Management Review Results ..... ...... 3-6

3.0.2.3 NRC-Approved Precedents ........................... :.... 3-6

3.0.2.4 UFSAR Supplement . 3-7

3.0.2.5 Documentation and Documents Reviewed .............. 3-7

3.0.3 Aging Management Programs . .3-7

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

3.0.3.2 AMPs That Are Consistent with the GALL Report with Exceptions

and/or Enhancements ............... ................ 3-23

3.0.3.3 AMPs That Are Plant Specific ....... ................ 3-76

3.0.4 Quality Assurance Program Attributes Integral to Aging Management

Programs ................... 3-144

3.0.4.1 Summary of Technical Information in the Application .... 3-145

3.0.4.2 Staff Evaluation . 3-145

3.0.4.3 Conclusion .3-146

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

.. ...... 3-146

3.1.1 Summary of Technical Information in the Application .... ........ 3-146

3.1.2 Staff Evaluation .................. ........................ 3-147

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

Which Further Evaluation Is Not Recommended .......... 3-156

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

Which Further Evaluation Is Recommended ..... ....... 3-161

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

the GALL Report .................................. 3-169

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

3.2 Aging Management of Engineered Safety Features Systems ..... ........ 3-207

3.2.1 Summary of Technical Information in the Application .... ........ 3-207

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

3.2.2.1 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which No Further Evaluation Is Required

.............................................. 3-210

3.2.2.2 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which Further Evaluation Is Recommended

. ........................................... 3-212

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

Not Addressed in the GALL Report ..................... 3-215

3.2.3 Conclusion ....... .. 3-242

3.3 Aging Management of Auxiliary Systems .. 3-242

3.3.1 Summary of Technical Information in the Application ..... ....... 3-242

3.3.2 Staff Evaluation ................... 3-243 ''. 

*3.3.2.1 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which No Further Evaluation Is Required 3-249

-vii- .
3.3.2.2 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which Further Evaluation Is Recommended ...

................................................. 3-252

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

Not Addressed in the GALL Report ....... ............. 3-259

3.3.3 Conclusion ........... 3-320

3.4 Aging Management of Steam and Power Conversion Systems ... ........ 3-320

3.4.1 Summary of Technical Information in the Application .... ........ 3-320

3.4.2 Staff Evaluation ........................................ 3-321

3.4.2.1 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which No Further Evaluation Is Required 3-324

3.4.2.2 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which Further Evaluation Is Recommended ...

. .................................... ......... 3-326

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

the GALL Report ................................. 3-330

3.4.3 Conclusion ............................................ 3-352

3.5 Structures and Component Supports ............ .. ................. 3-353

3.5.1 Summary of Technical Information in the Application .... ........ 3-353

3.5.2 Staff Evaluation ........................................ 3-353

3.5.2.1 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which No Further Evaluation Is Required 3-359

3.5.2.2 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which Further Evaluation Is Recommended ...

eut htAeNtCnitn.... .M .... 3-366 ...................... . . . . . . . . . . .. . . . . . . . . . . .. . . . ........... 3-6

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

Are Not Addressed in the GALL Report .... ........... 3-384

3.5.3 Conclusion ............................................ 3-402

3.6 Aging Management of Electrical and Instrumentation and Controls ........ 3-402

3.6.1 Summary of Technical Information in the Application .... ........ 3-402

3.6.2 Staff Evaluation ......................................... 3-402

3.6.2.1 Aging Management Evaluations That Are Consistent with the

GALL Report, for Which No Further Evaluation Is Required 3-405

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

Which Further Evaluation Is Recommended ..... ....... 3-412

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

Not Addressed in the GALL Report ................... 3-413

3.6.3 Conclusion ............................................ 3-419

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

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

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

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

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

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

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

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

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

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

-viii-
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 ...... 4-9

4.2.3.2 Staff Evaluation ................................... 4-9

4.2.4 UFSAR Supplement . . . ............ 4-10

4.2.5 Conclusion . . . .............. 4-10

4.3 Metal Fatigue . . ................ 4-10

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

4.3.2 Staff Evaluation .......................................... 4-11

4.3.3 UFSAR Supplement ...................................... 4-17

4.3.4 Conclusion . . ........................................... 4-18

4.4 Environmental Qualification of Electrical Components ......... ........... 4-18

4.4.1 Summary of Technical Information in the Application ..... ........ 4-18

4.4.2 Staff Evaluation ......................................... 4-19

4.4.3 Conclusion . . ........................................... 4-19

4.5 Concrete Containment Tendon Prestress ....... .. . . 4-19

4.5.1 Summary of Technical Information in the Application ..... ........ 4-19

4.6 Containment Liner Plate and Penetration Fatigue Analyses ............... 4-20

4.6.1 Summary of Technical Information in the Application ..... ........ 4-20

4.6.2 Staff Evaluation ......................................... 4-21

4.6.3 UFSAR Supplement . ...................................... 4-22

4.6.4 Conclusions ............ 4-22

4.7 Other Plant-Specific Time-Limited Aging Analyses ........... ........... 4-22

4.7.1 Reactor Coolant System Piping Leak Before Break ..... ......... 4-23

4.7.1.1 Summary of Technical Information in the Application ..... 4-23

4.7.1.2 Staff Evaluation ............... ................... 4-23

4.7.1.3 UFSAR Supplement ........... .. ................. 4-24

4.7.1.4 Conclusion ....................... 4-24

4.7.2 ASME Code Case N-481 ........ .......................... 4-25

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

4.7.2.2 Staff Evaluation .................................. 4-25

4.7.2.3 UFSAR Supplement .............................. 4-26

4.7.2.4 Conclusion ...................................... 4-26

4.7.3 Ice Condenser Lattice Frame .............. ................. 4-26

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

4.7.3.2 Staff Evaluation .................................. 4-27

4.7.3.3 UFSAR Supplement .............................. 4-29

4.7.3.4 Conclusion ...................................... 4-29

4.7.4 Reactor Vessel Underclad Cracking .......................... 4-29

4.7.4.1 Summary of Technical Information in the Application ..... 4-29

4.7.4.2 Staff Evaluation .................................. 4-30

4.7.4.3 UFSAR Supplement .............................. 4-31

4.7.4.4 Conclusion ...................................... 4-31

4.7.5 Steam Generator Tube Flow-induced Vibration ...... ........... 4-31

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

4.7.5.2 Staff Evaluation .................................. 4-31

4.7.5.3 UFSAR Supplement .............................. 4-32

4.7.5.4 Conclusion .......... ............................ 4-32

-ix-
4.7.6 Fatigue Analysis of Cranes ........ ........................ 4-32

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

4.7.6.2 Staff Evaluation .................................. 4-33

4.7.6.3 UFSAR Supplements .............................. 4-33

4.7.6.4 Conclusions ..................................... 4-33

4.7.7 Reactor Coolant Pump Flywheels ........................... 4-33

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

4.7.7.2 Staff Evaluation .................................. 4-33

4.7.7.3 UFSAR Supplement .............................. 4-34

4.7.7.4 Conclusions ..................................... 4-34

4.8 Conclusions for TLAAs ................... 4-34

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

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

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

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

APPENDIX C: REFERENCES ..................... .......................... C-1

APPENDIX D: PRINCIPAL CONTRIBUTORS ............... .................... D-1
ABBREVIATIONS

ac alternating current

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ACSR aluminum conductor steel reinforced

ADAMS Agencywide Documents Access and Management System

AEC Atomic Energy Commission

AEP American Electric Power

AERM aging effect requiring management

AFW auxiliary feedwater

AISC American Institute of Steel Construction

AMP aging management program

AMR aging management review

AMRR aging management review reports

ANSI American National Standards Institute

APCSB auxiliary and power conversion systems branch

ARDM age related degradation mechanism

AS auxiliary steam

ASME American Society of Mechanical Engineers

AST alternate source term

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

AVB antivibration bar

BD blowdown

BMI bottom-mounted instrumentation

B&PV Boiler and Pressure Vessel

BTP branch technical position

B&W Babcock and Wilcox Co.

BWR boiling-water reactor

CASS cast austenitic stainless steel

CC concrete containments

CCP centrifugal charging pump

CCW component cooling water

CE Combustion Engineering

CEQ containment equalization / hydrogen skimmer system

CF chemical feed

CFR Code of Federal Regulations

Cl confirmatory item

CLB current licensing basis

CMAA Cran6 Manufactures Association of America

CNP Donald C. Cook Nuclear Plant

C02 carbon dioxide

CR condition report

CRDM control rod drive mechanism

CST condensate storage tank

-xi-
CUF cumulative usage factor

CTRL control air

CVC chemical and volume control system

CW circulating water

DBD design basis document

DBE design basis event

DE Division of Engineering

DEMIN demineralized water

DEQ Department of Environmental Quality

DRAIN process drains - miscellaneous drain tank

ECCS emergency core cooling system

ECT eddy current testing

EDG emergency diesel generator

EFPY effective full power year

EPRI Electric Power Research Institute

EQ environmental qualification

EQDB equipment qualification database

ER Environmental Report

ES engineering services

ESF engineered safety features

ESFAS engineered safety feature actuation system

ESRR Expanded System Readiness Review

ESW essential service water

FAC flow-accelerated corrosion

FDB facility database

FERC Federal Energy Regulatory Commission

FIV flow-induced vibration

FMP fatigue monitoring program

FP fire protection

FPPM Fire Protection Program Manual

FRV feedwater regulating valve

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

HE heat exchanger

HELB high energy line break

HPSI high-pressure safety injection

HVAC heating, ventilation, and air conditioning

-xii-
IASCC

l&C

ICE

ICLF

IGA

IGSCC

l&M

IN

INPO

IPA

ISG

ISI

ISSR

ITG

irradiation-assisted stress corrosion cracking

instrumentation and controls

ice condenser

ice condenser lattice frames

intergranular attack

intergranular stress corrosion cracking

Indiana Michigan Power Company

information notice

Institute of Nuclear Power Operations

integrated plant assessment

interim staff guidance

inservice inspection

individual system / structure reports

issues task group

ksi kips per square inch

LAS

LBB

LER

LOCA

LRA

LRP-MAMR

LRP-PG

LRP-TR

LTOPS

LTW

M

MATL

MDAFP

MDEQ

MeV

MIC

MRP

MSLB

MSS

MT

MWe

MWt

n/cm2

N2

NDE

NDT

NEI

NEPA

NESW

NF

low alloy steel

leak before break

licensee event report

loss-of-coolant accident

license renewal application

License Renewal Project Mechanical Aging Management Report

License Renewal Project Guideline

Topical Report for License Renewal Scoping

low temperature overpressure protection system

Lake Charter Township water

margin value to account for uncertainties

material/equipment handling

motor-driven auxiliary feedwater pumps

Michigan Department of Environmental Quality

million electron volts

microbiologically induced or influenced corrosion

Materials Reliability Project

main steam line break

Manufacturers Standardization Society

main turbine

megawatt-electric

megawatt-thermal

neutron per square centimeter

reactor nitrogen system

nondestructive examination

nil ductility transition

Nuclear Energy Institute

National Environmental Policy Act of 1969

nonessential service water system

nuclear fuel

-xiii-
I 

I

NFPA National Fire Protection Association

NPS nominal pipe size

NRC Nuclear Regulatory Commission

NRR Nuclear Reactor Regulation

NS nuclear sampling

NSSS nuclear steam supply system

NUMARC Nuclear Management and Resource Council

NUREG NRC technical rapport designation

OBE operating-basis earthquake

ODSCC outer diameter stress corrosion cracking

OFPW offsite power

PA plant air

PACHMS post-accident containment hydrogen monitoring system PASS post-accident sampling system

P&ID piping and instrumentation diagram

PORV power operated relief valve

ppb parts per billion

ppm parts per million

PRT pressurizer relief tank

PSDC plant-specific design criteria

PTS pressurized thermal shock

P-T pressure-temperature

PW primary water

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance

QAPD Quality assurance Program description

RAI request for additional information

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RG regulatory guide

RHR residual heat removal

RIS NRC Regulatory Issue Summary

RLEP NRR License Renewal and Environmental Impacts Program Branch

RPV reactor pressure vessel

RMS radiation monitoring system

RT reference temperature

RTpTs reference temperature for pressurized thermal shock

RTNDT reference nil ductility transition temperature

RV reactor vessel

RVH reactor vessel head

RVI reactor vessel internals

RVID Reactor Vessel Integrity Database

RVLIS reactor vessel level indication system

-xiv-
RVSP Reactor Vessel Surveillance Program

RWD radioactive waste disposal

RWST refueling water storage tank

SBO station blackout

SC structure and component

SCC stress corrosion cracking

SCRN screen wash

SCW provide source of cooling

SD station drainage

SE safety evaluation

SER safety evaluation report

SFP spent fuel pool

SG steam generator

SGBD steam generator blowdown

Si safety injection

SMP Structures Monitoring Program

SOC Statements of Consideration

SRP-LR Standard Review Plan - License Renewal

SRXB NRR Reactor Systems Branch

SSC structure system and component

SSD safe shutdown

SW service water

TDAFP turbine-driven AFW pump

TDR time domain reflectometry

TLAA time-limited aging analysis

UFSAR updated final safety analysis report

USAS United States of America Standard

USE upper shelf energy

VA auxiliary building ventilation system

VAB auxiliary building ventilation

VCONT containment ventilation

VCRAC control room ventilation system

VEDG emergency diesel generator ventilation system

VES engineered safety features ventilation

VHP vessel head penetration

VMISC miscellaneous ventilation

VSFP spent fuel pool ventilation

VSWGR switchgear ventilation system

VT visual test

WCAP Westinghouse Commercial Atomic Power

WOG Westinghouse Owner's Group

XLPE cross-linked polyethylene

-xv-
1. INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

Donald C. Cook Nuclear Plant (CNP), Units 1 and 2, as filed by the Indiana Michigan Power

Company (I&M or the applicant). By letter dated October 31, 2003, 1&M submitted its

application to the U.S. Nuclear Regulatory Commission (NRC or the staff)'for renewal of the

CNP operating license for an additional 20 years. The NRC staff (the staff) prepared this

report, which summarizes 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). The

NRC license renewal project manager for the CNP license renewal review is Mr. Jonathan'

Rowley. Mr. Rowley may be contacted by calling 301-415-4053, emailing JGR~nrc.aov, or

writing to the License Renewal and Environmental Impacts Program, Office of Nuclear Reactor

Regulation, U.S. Nuclear Regulatory Commission, Washington, DC, 20555-0001.

In its October 31, 2003, submittal letter, the applicant requested renewal of the operating

license issued under Section 104b of the Atomic Energy Act of 1954, as amended (Facility

Operating' License'Number DPR-58 and DPR-74) for a period of 20 years beyond the current

license expiration dates of midnight, October 25,' 2014, and December 23, 2017, for Units 1 and

2, respectively. The CNP site is located along the eastern shore of Lake Michigan in Lake

Charter Township, Berrien County, Michigan. The NRC issued the CNP construction permit for

Units 1 and 2 on March 25,1974, and the operating license for Units 1 and 2 on October 25,

1974, and December 23, 1977, respectively. Units 1 and 2 of CNP consist of Westinghouse

Electric pressurized-water reactors (PWRs) licensed to generate 3304 and 3468 megawattsthermal (MWt), or approximately 1080 and 1155 megawatts-electric (MWe), respectively.

Details concerning the plant and the site appear in the Updated Final Safety Analysis Report

(UFSAR).

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

safety issues and an environmental review. The NRC regulations at 10 CFR Part 54 and

10 CFR Part 51, "Environmental Protection Regulations for Domestic Licensing'and Related

Regulatory Functions," respectively, state the requirements for these reviews. The safety

review for the CNP license renewal is based on the-applicant's-license renewal application

(LRA) and on the responses to requests for additional information '(RAls) from the staff. During

audits and meetings and in docketed correspondence, the applicant supplemented its'

responses to the LRA and RAls. Unless otherwise noted, the staff reviewed and considered

information submitted through March 24, 2005. The staff reviewed informatioh' received after

that date on a case-by-case basis, depending on'the stage of the safety review and the volume

and complexity of the information. The LRA and'all pertinent information and materials,

including the UFSAR mentioned above, are available to the public for review at the NRC Public

DocumentRoom, -11555 Rockville Pike, Room 01- F21, Rockville; Maryland, '20852-2738 (301-

415-4737/800-397-4209), at the Bridgman Public Library in Bridgman, Michigan, and at the St.

JosephMaud Preston Palenske Memorial Library in St. Joseph, Michigan'. Materials related to

the LRA are also available through the NRC's Web site, at httD://www.nrc.aov.

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

the scope of the technical details considered in evaluating the safety aspects of the CNP

proposal to operate for an additional 20 years beyond the term of the current operating license.

The staff reviewed the LRA in accordance with the NRC regulations and the guidance provided

in NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for

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

Sections 2 through 4 of the SER address the staff's review and evaluation of license renewal

issues considered during the examination of the application. Section 5 is reserved for the

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

conclusions of this report.

Appendix A to this SER identifies the applicant's commitments associated with the renewal of

the operating licenses. Appendix B provides a chronology of the NRC's and the applicant's

principal correspondence related to the review of the application. Appendix C gives the

references used during the course of the review. Appendix D lists the principal contributors to

the SER.

In accordance with 10 CFR Part 51, the staff prepared a draft for comment, and a final plantspecific supplement to the Generic Environmental Impact Statement (GEIS) that discusses the

environmental considerations related to renewing the license for CNP, Units 1 and 2. The staff

issued NUREG-1437, Supplement 20, "Generic Environmental Impact Statement for License

Renewal of Nuclear Plants: Regarding Donald C. Cook Nuclear Plant, Units No. 1 and 2, Final

Report," in May 2005.

1.2 License Renewal Background

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

licenses for commercial power reactors to operate for 40 years. These licenses can be

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

basis of economic and antitrust considerations-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 the interest

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

nuclear plant aging research. On the basis 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 Rule). The NRC

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

and to develop experience to establish 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

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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

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 Rule changes ensure that important systems, structures,' and

components (SSCs) will continue to perform their intended functions during the period of

extended operation. In addition, the changes clarified and simplified the integrated plant

assessment (IPA) process to ensure consistency 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

fulfilling the NRC's responsibilities under the National Environmental Policy Act of 1969 (NEPA).

1.2.1 Safety Review

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

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

operating plants 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 in

the period of extended operation, 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 to

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

functions, and (3) that are relied on to demonstrate compliance with the NRC's regulations for

fire protection (FP), environmental qualification (EQ), 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 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 it will manage the effects of aging 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. Active equipment, however, is :

considered 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 identified and corrected through routine surveillance and maintenance or revealed

through performance indicators. The surveillance and maintenance programs for active

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

1-3 '
I

required throughout the period of extended operation. Pursuant to 10 CFR 54.21 (d), a

supplement to the final safety analysis report (FSAR) must contain a summary description of

the programs and activities for managing the effects of aging.

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 July 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 of implementing the License Renewal Rule. The NEI guideline is NEI

95-10, Revision 3, industry Guideline for Implementing the Requirements of 10 CFR Part

54-The License Renewal Rule," issued March 2001. The NRC also prepared the SRP-LR,

which the staff used to review this application.

The applicant used the process defined in NUREG-1801, "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

staff can greatly reduce the time, effort, and resources used to review an applicant's LRA,

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 and 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

The environmental protection regulations are governed by 10 CFR Part 51. The NRC revised

these regulations in December 1996 to facilitate the environmental review for license renewal.

The staff prepared a GEIS, in which it examined the possible environmental impacts associated

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

the GEIS establishes generic findings that are applicable to all nuclear power plants. Subpart A

of Appendix B, "Environmental Effect of Renewing the Operating License of a Nuclear Power

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

10 CFR 51.53(c)(3)(i), an applicant for license renewal may incorporate these generic findings

in its environmental report. The environmental report must include analyses of those

environmental impacts that must be evaluated on a plant-specific basis (Category 2 issues) 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 the existence of new

1-4
and significant information not considered in the GEIS. The staff held a public meeting on

November 20, 2003, in Bridgman,WMichigan, as part of the NRC's scoping process, to identify

environmental issues specific to the plant. Results of the environmental review and a

preliminary recommendation for the license renewal action appear in the NRC's draft plantspecific supplement to the GEIS, which the NRC issued on September 17, 2004, and discussed

at a separate public meeting on November 9, 2004, in Bridgman, Michigan. After consideration

of comments on the draft, the NRC will prepare and publish a final plant-specific supplement to

the GEIS. These documents are published separately from this report.

1.3 Principal Review Matters

The staff performed its technical review of the CNP LRA in accordance with Commission

guidance, the requiremfents for renewing operating'licenses for nuclear power plants in

10 CFR Part 54, and the specific standards for license renewal in 10 CFR 54.29, "Standards for

Issuance of a Renewed 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 CNP,

submitted by letter dated October 31, 2003. The 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 54.1 9(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:

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

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

account for the expiration term of the proposed renewed license." The current

indemnity agreement (No. B-61) for CNP 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. 7,

lists CNP special nuclear, material licenses SNM-1 301 and SNM-1753, and

operating licenses DPR-58 and DPR-74- l&M 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 to the expiration date

of the renewed CNP facility operating licenses sought in this application. In

addition, should the license numbers be changed upon issuance of the renewal

license, I&M requests that conforming changes be made to Item 3 of the

Attachment to the indemnity agreement, and to other sections of the agreement.

as deemed appropriate.

The staff intends to maintain the license numbers upon 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.

1-5
In 10 CFR 54.21, "Contents of Application-Technical Information," the Commission requires

that each application for a renewed license for a nuclear facility must contain (a) an IPA, (b) a

description of CLB changes during staff review of the application, (c) an evaluation of TLAAs,

and (d) an FSAR supplement. Sections 3 and 4 and Appendices A and B to the LRA address

the license renewal requirements of 10 CFR 54.21 (a), (c), and (d) respectively.

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 FSAR Supplement.

In accordance with 10 CFR 54.22, "Contents of Application-Technical Specifications," 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 CNP 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. The staff's

evaluation of the technical information appears in Sections 2, 3, and 4 of this report.

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

10 CFR 54.23, "Contents of Application-Environmental Information," in the final plant-specific

supplement to the GEIS that specifies the considerations related to renewing the licenses for

CNP. The staff will prepare this supplement separately from this SER. As required by

10 CFR 54.25, "Report of the Advisory Committee on Reactor Safeguards," the ACRS will issue

a report documenting its evaluation of the staff's LRA review and 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 contribute 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 and issues them to the public for comment, modifies them as necessary to resolve

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

stakeholders until the improved license renewal guidance documents are revised.

Table 1-1 presents the current set of relevant ISGs issued by the staff and the SER sections in

which the staff addresses these issues.

1-6
Table 1-1 Relevant Interim Staff Guidance

ISG Issue Purpose SER

(Approved ISG No.) - -Section

Station Blackout Scoping The License Renewal Rule 10 CFR 54.4(a)(3) 2.1.3.1.2,

(ISG-2) includes 10 CFR 50.63(a)(1)-SBO. 3.6.2.3.4

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 (EDGs). -

The offsite power system should be within the

scope of license renewal.

Concrete Aging Lessons learned from the GALL demonstration 3.5.2.1.1,

Management Program project indicate that the GALL Report is not 3.5.2.2

(ISG-3) clear whether concrete requires any AMPs.

Fire Protection System The ISG clarifies the staff position for wall 3.0.3.2.5,

Piping (ISG-4) thinning of FP piping system in GALL AMPs 3.0.3.2.6

XL.M26 and XL.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, use a

nonintrusive method such as volumetric

inspection.

Sprinkler heads should be tested 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.:

1-7
I~

ISG Issue Purpose | SER

(Approved ISG No.) | Section

Identification and The ISG includes the fuse holder AMR and 2.1.3.1.4,

Treatment of Electrical AMP (i.e., same as terminal blocks and other 3.6.2.3.3

Fuse Holder (ISG-5) electrical connections).

The position includes only fuse holders 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

age-related 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.

Revision to GALL (ISG-15) The ISG clarifies and incorporates NEI's 3.0.3.2.9,

proposed revision to GALL AMP XI.E2 (i.e. 3.6.2.1.1

replaced technical specification surveillance

with specific calibrations or surveillance).

1.5 Summary of Open Items

As a result of its review of the LRA for CNP, including additional information submitted to the

NRC through November 19, 2004, the staff identified two issues that remained open at the time

the SER with Open Items was published. The staff considers an issue open if the applicant has

not presented a sufficient basis for resolution, or if the staff has not yet reviewed information

provided in recent submittals from the applicant. Each open item has a unique identifying

number. By letter dated January 21, 2005, the applicant responded to these open items. The

staff reviewed the responses and has closed out each of the open items. The basis for closing

the open items is as follows:

Item Description

3.3.2.1.11-1 The staff did not find the applicant's initial response to RAI 3.3.2.1.11-1

acceptable. The staff's specific concern, described in RAI 3.3.2.1.11-1, is the

apparent aging management of the internal environments of

components/systems by visual inspection of external surfaces if environmental

differences exist between internal and external surfaces. While external

inspection of component condition (e.g. pipes, valves) can indicate the

components' internal condition, this is generally not the case until internal

degradation results in loss of component integrity as might be indicated by a

system leak. The applicant has not provided sufficient information to

1-8
demonstrate that aging effects on internal surfaces of various components in

miscellaneous systems will be effectively managed by the System Walkdown

Program. The staff asked the applicant to provide further justification for the use

of the System Walkdown Program to manage aging effects for all components

identified in LRA Table 3.3.2-11 with different internal and external environments

sufficiently to maintain the intended function of the components and ensure that

operation of safety related equipment will not be jeopardized during the period of

license renewal.

Resolution By letter dated January 21, 2005, the applicant provided additional information in

response to Open Item 3.3.2.1.11-1.

As shown in LRA Table 3.3.2-11, in addition to System Walkdown Program, the

Water Chemistry Control Program will manage the effects of aging on the

components with an internal environment of treated water, except for level glass

gauges and molded plastic tanks. Because the glass in the level gauges is

inherently resistant to potential aging effects in air, treated water, raw or

untreated water, or untreated borated water environments, it has no aging

effects requiring management. The molded plastic tanks in the ice condenser

system are exposed to an internal treated water environment (i.e., glycol mixture)

that is monitored by the Auxiliary Systems Water Chemistry Control Program

described in LRA Section B.1.40.3.

Additionally, as indicated in LRA Table 3.3.2-11, the Flow-Accelerated Corrosion

Program will also manage the effects of aging on components with an internal

steam environment, except for copper heater coils, cast iron strainer housings

and carbon steel traps. I&M will include the auxiliary steam system copper

heater coils, cast iron strainer housings, and carbon steel traps exposed to an

internal steam environment in the Chemistry One-Time Inspection Program,

which is described in LRA Section B.1.41.

The remaining components in LRA Table 3.3.2-11 with differing internal and

external environments that credit only the System Walkdown Program for aging

management are exposed to internal raw or untreated water environments. The

following table identifies the fluid-filled mechanical systems that contain these

components.

SYSTEM CODE SYSTEM NAME

CF Chemical Feed

CONT Containment

DRAIN Process Drains

LTW` Lake Township Water

NESW Non-Essential Service Water

NS Nuclear Sampling

PASS Post-Accident Sampling

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SYSTEM' CODE SYSTEM NANIE

RMS Radiation Monitoring

RWD Radioactive Waste Disposal

SD Station Drainage

The following discussion provides additional basis for acceptability of other

programs for managing the effects of aging on the CF, LTW, NESW, and NS

systems that have components containing raw or untreated water.

1. The CF system contains water treated with chemicals to reduce corrosion

in the steam generators. This environment was conservatively classified

as untreated water although it is actually chemically treated.

2. The LTW system contains water that has been chemically treated by the

municipality prior to being used at the site, but was conservatively

classified as untreated water in the aging management review. Because

LTW chemistry is not controlled by CNP, a chemistry control program

was not credited in the LRA. However, as documented in l&M's

supplemental response to RAI 3.3.2.1.9-6 in this letter, the extent of

aging effects on security diesel system components containing LTW will

be confirmed by the Chemistry One-Time Inspection Program, which will

inspect a representative sample of 10 CFR 54.4(a)(2) components in the

LTW system.

3. The NS system contains heat exchangers exposed to an internal raw

water (NESW) environment. The NESW system has the same suction

source and is chemically treated in the same manner as the essential

service water (ESW) system. The Service Water System Reliability

Program will manage the effects of aging on 10 CFR 54.4(a)(2)

components containing NESW, because these components are

fabricated from the same materials and are exposed to the same

environments as components in the ESW system.

The remaining systems (CONT, DRAIN, PASS, RMS, RWD, and SD) have

copper alloy, carbon steel, stainless steel, or glass components that may be

pressurized and contain raw or untreated water. As discussed previously, glass

exposed to raw or untreated water exhibits no aging effects requiring

management. I&M will include these 10 CFR 54.4(a)(2) components that are

subject to aging management review in the Chemistry One-Time Inspection

Program.

Loss of material, if any, from the 10 CFR 54.4(a)(2) components discussed

above is expected to progress slowly. The one-time inspection of these

components will provide assurance that loss of material is occurring at a rate

slow enough to ensure that the intended functions of the components will be

maintained during the period of extended operation. This one-time inspection

will be performed near the end of the current operating term. The visual

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inspections will identify indications of loss of material. If loss of material is

identified, an evaluation will be performed to confirm that the rate is sufficiently

slow that loss of intended function will not occur during the period of extended

operation. For material and environment combinations with no evidence of loss

of material or with very gradual loss of material, no further actions will be taken.

For material and environment combinations with loss of material rates such that

loss of intended function could occur during the period of extended operation,

corrective actions will be taken in accordance with the Corrective Action

Program. Appropriate corrective actions may consist of component replacement

or additional inspections for components with the material and environment

combination in which the excessive loss of material is found.

The supplemental response is reasonable and acceptable to the staff because

the applicant has provided sufficient information to demonstrate that aging

effects on internal surfaces of various components in miscellaneous systems will

be effectively managed by the application of a combination of the FlowAccelerated Corrosion Program, Chemistry One-Time Inspection Program and

the Service Water System Reliability Program. The application of the One-Time

Inspection Program is appropriate for those components where loss of material

is expected to progress slowly and the applicant has identified that the inspection

will be performed near the end of the current operating term with appropriate

corrective actions. On the basis of the supplemental information submitted by

the applicant, all issues related to Open Item 3.3.2.1.11-1 are resolved. The

application of the Chemistry One-Time Inspection Program discussed above is

specified in Commitment #39 in Appendix A of this SER.

B.1.12-1 In CNP LRA, Appendix B, Section B.1.12, the applicant states that CNP AMP

B1.12, "Flow-Accelerated Corrosion Program," is consistent with GALL AMP

XI.M17. During the audits and inspections, the staff noted that CNP's FlowAccelerated Corrosion (FAC) Program is consistent but with an exception. The

Monitoring and Trending element of GALL AMP XI.M1 7 requires that if

degradation is detected such that the wall thickness is less than the minimum

predicted thickness, additional examinations are performed in adjacent areas to

bound the thinning. However, CNP's FAC program bases its sample expansion

determination on a threshold criteria rather than on predicted thickness. Sample

size is increased when inspections detect significant FAC wear resulting in a wall

thickness threshold of less than or equal to 60 percent of nominal wall thickness.

In RAI B.1.12-1, the staff requested that the applicant provide a description of

the FAC Program, as modified by the exception, and justification for the

exception regarding the criteria for performing additional examinations by

expanding the sample size. - -

Resolution By letter dated January 21, 2005, the CNP provided additional information in

response to RAI B.1.12-1, indicating that the AMP is consistent with GALL, with

an exception.

In the FAC Program description in GALL Section XI.M17, the Monitoring and

Trending section states, in part, that, "If degradation is detected such that the

wall thickness is less than the minimum predicted thickness, additional

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examinations are performed in adjacent areas to bound the thinning." CNP

stated that literal implementation of this statement from the GALL description is

not practical in many cases. If very little degradation is predicted, measured wall

thickness may be less than the predicted thickness even though the calculated

life of the affected component may exceed the operating life of the plant. In this

case, sample expansion would not be warranted. Therefore, the applicant took

an exception to the Monitoring and Trending attribute of GALL, Section XI.M17.

The staff noted that the CNP FAC Program is based on industry guidance in the

Electric Power Research Institute (EPRI) report NSAC-202L-R2,

"Recommendations for an Effective Flow-Accelerated Corrosion Program," dated

April 1999, which recommends increasing the sample size when inspections of

the sample detect significant FAC wear. In the CNP FAC Program, significant

FAC wear is defined as FAC resulting in a wall thickness of less than or equal to

60 percent of nominal wall thickness. Sample expansion is typically required if

any component is determined to have a wall thickness of less than or equal to 60

percent of nominal wall thickness (must be greater than allowed minimum wall

thickness). In addition, the staff noted that CNP FAC procedures require that a

sample expansion be performed when inspection results indicate that a

component has a remaining life less than one operating cycle based on a

trending of wall thickness measurements. This covers situations where the

minimum wall thickness required may be greater than 60 percent of nominal wall

thickness.

The staff found this exception to GALL for sample expansion to be acceptable

because literal implementation of the sample expansion criterion is not practical

in all cases, particularly when the predicted wall thickness change is small and

the change is close to the measurement capabilities. Additionally, the staff finds

this exception acceptable since the applicant trends expected wall thinning

values and requires that the projected acceptable wall thickness be above a

threshold value that is above 60% nominal wall and above minimum wall. On the

basis of the supplemental information submitted by the applicant, all issues

related to RAI B.1.12-1 are resolved.

1.6 Summary of Confirmatory Items

As a result of its review of the LRA for CNP, including additional information submitted to the

NRC through November 19, 2004, the staff identified the two issues that remained confirmatory

items at the time the SER with Open Items was published. Confirmatory items are items for

which the staff and the applicant had reached a satisfactory resolution, but the applicant had

not yet formally submitted a resolution to the staff. By letter dated January 21, 2005, the

applicant responded to these items. The staff reviewed the responses and has closed each of

the confirmatory items. The basis for closing the confirmatory items is as follows:

Item Description

4.3-1 The applicant provided a UFSAR supplement description of the Fatigue

Monitoring Program (FMP) in Section A.2.1.12 of the LRA and a description of its

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TLAA evaluation for Class 1 and non-Class 1 component fatigue analyses in

Section A.2.2.2 of the LRA. The staff requested that the applicant update

Section A.2.2.2 to include the following: (1) a discussion of each of the actions

selected for commitment to evaluate the auxiliary spray line piping and (2) a

discussion of each of the actions selected for commitment to evaluate the

environmental fatigue of the safety injection nozzles, charging nozzles and the

RHR line.

Resolution The applicant's January 21, 2005, response provided the updated UFSAR

Supplement for Section A.2.2.2. The updated UFSAR Supplement contains a

discussion of the applicant's commitment to perform additional actions to

address fatigue of the auxiliary spray line piping prior to the period of extended

operation and its commitment to perform additional actions to address

environmental fatigue of the pressurizer surge line, safety injection nozzles,

charging nozzles and the RHR line prior to the period of extended operation.

The staff considered these additional proposed actions and found them

acceptable. The staff concludes that the revised UFSAR Supplement

adequately describes the applicant's actions to address metal fatigue.

Therefore, Confirmatory Item 4.3-1 is closed. The above mentioned

commitments are specified in Commitment #40, #31, #33, and #35 in Appendix

A of this SER.

4.6-1 The applicant provided a UFSAR supplement describing its TLAA evaluation for

containment liner plate and penetration fatigue analyses in Section A.2.2.4 of the

LRA. The staff requested that the applicant update the UFSAR Supplement to

capture its commitment to analyze the containment penetrations.

Resolution The applicant's January 21, 2005, response provided the updated UFSAR

Supplement for Section A.2.2.4. The updated UFSAR Supplement contains a

discussion of the applicant's commitment to analyze the containment

penetrations. The staff concludes that the revised UFSAR Supplement

adequately describes the applicant's actions to address the containment liner

plate and penetration fatigue analyses. Therefore, Confirmatory Item 4.6-1 is

closed. The above mentioned commitment is Commitment # 34 in Appendix A of

this SER.

1.7 Summary of Proposed License Conditions

As a result of the staff's review of the CNP 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 UFSAR Supplement required by

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

of the renewed license.

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

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

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The following describes the third license condition:

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 Scopinqc and Screeninc Methodology

2.1.1 Introduction

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

of the Code of Federal Regulations (10 CFR Part 54), specifically 10 CFR 54.21, "Contents of

Application-Technical Information," requires that each application for license renewal contain

an integrated plant assessment (IPA). The IPA must list and identify those structures, systems,

and components (SSCs) that are within the scope of license renewal in accordance with

10 CFR 54.4 and subject to an aging management review (AMR).

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 the SSCs at

the Donald C. Cook Nuclear Power Plant (CNP) that are within the scope of license renewal

and subject to an AMR. The staff reviews the applicant's scoping and screening methodology

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

requirements stated in 10 CFR 54.21 (a)(1).

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

considered the requirements of 10 CFR Part 54, the Statements of Consideration related to the

License Renewal Rule, and the guidance provided in Nuclear Energy Institute (NEI) 95-10,

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

Renewal Rule." In addition, the applicant also considered the Nuclear Regulatory Commission

(NRC) staff's license renewal interim staff guidance (ISG) documents and related

correspondence.

2.1.2 Summary of Technical Information in'the Application

In Sections 2.0 and 3.0 of the LRA, the applicant provided the technical information required by

10 CFR 54.21 (a). In Section 2.1 of the LRA, "Scoping and Screening Methodology," 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 SSCs that are

subject to an AMR as required by 10 CFR 54.21 (a)(1). Additionally, LRA Section 2.2, "PlantLevel Scoping Results," Section 2.3, "Scoping and Screening Results: Mechanical Systems,"

Section 2.4, "Scoping and Screening Results: Structures," and Section 2.5, "Scoping and

Screening Results: Electrical and Instrumentation and Control Systems," provide results of this

process and identify structures and components (SCs) subject to an AMR.

2.1.2.1 Scoping Methodology

In Section 2.1 of the LRA, the applicant described the methodology it used to scope

mechanical, structural, and electrical and instrumentation and controls (I&C) SSCs pursuant to

the scoping criteria of 10 CFR 54.4(a). The following sections describe the applicant's scoping

methodology, as described in the LRA.

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

The applicant described the general approach to scoping safety related, nonsafety related, and

systems and structures credited with demonstrating compliance with certain regulated events in

Section 2.1.1, "Scoping Methodology," of the LRA. The applicant stated that, consistent with

NEI 95-10, the scoping process used for the CNP license renewal project began with a list of

plant systems and structures. The applicant then identified the functions performed by these

systems and structures and determined which of these functions met the scoping criteria of

10 CFR 54.4(a). The following sections describe the scoping approaches specific to the

10 CFR 54.4(a) scoping criteria for safety related SSCs, nonsafety related SSCs, and SSCs

required to mitigate regulated events.

Application of the Scoping Criteria in 10 CFR 54.4(a)(1). In Section 2.1.1.1, "Application of

Safety related Scoping Criteria," of the LRA, the applicant discussed the methodology used to

identify SSCs meeting the 10 CFR 54.4(a)(1) safety related license renewal scoping criteria.

The applicant stated that it reviewed system and structure functions and considered them to be

a safety intended function if one or more of the three safety related scoping criteria of

10 CFR 54.4(a)(1) were met. The applicant placed systems or structures that perform a safety

related intended function within the scope of license renewal. However, the applicant stated

that, because of plant-specific considerations or preferences, some components may have

been classified as safety related that do not have safety related intended functions.

Consequently, the applicant noted that it could treat an SSC that does not meet the

10 CFR 54.4(a)(1) safety related scoping criteria as safety related under other CNP programs

for plant-specific reasons.

Application of the Scoping Criteria in 10 CFR 54.4(a)(2). In Sections 2.1.1.2, "Application of

Criterion for Nonsafety related SSCs Whose Failure Could Prevent the Accomplishment of

Safety Functions," and 2.1.3, "Interim Staff Guidance Discussion," of the LRA, the applicant

discussed the methodology used to identify systems and structures meeting the

10 CFR 54.4(a)(2) nonsafety related license renewal scoping criteria. The applicant considered

the following three categories of nonsafety related systems and structures when performing

10 CFR 54.4(a)(2) scoping evaluations:

(1) nonsafety related equipment required to remain functional in support of a safety

related function

(2) nonsafety related SSCs directly connected to safety related SSCs, and

(3) nonsafety related SSCs that are not directly connected to safety related SSCs but

have the potential for adverse spatial interactions with safety related equipment.

The applicant described the methods used to scope each of these categories of nonsafety

related systems and structures in LRA Section 2.1.1.2.

Nonsafety related SSCs Required to Support Safety related SSCs

In Section 2.1.1.2.1, "Functional Failures of Nonsafety related SSCs," of the LRA, the applicant

noted that, with few exceptions, it 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

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renewal under the 10 CFR 54.4(a)(1) scoping criteria. However, the applicant stated that, for

the few exceptions in which nonsafety related equipment is required to remain functional to

support a safety function, the supporting systems were included Within the scope of license

renewal.

Nonsafety related SSCs Directly Connected to Safety related SSCs

The applicant described the scoping of nonsafety related SSCs directly attached to safety

related piping in Section 2.1.1.2.2, "Spatial Failures of Nonsafety related SSCs," of the LRA.

The applicant stated that, for piping systems, 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: 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.

Nonsafety related SSCs Not Directly Connected to Safety related SSCs with the Potential for

Spatial Interaction

The applicant described the scoping of nonsafety related SSCs that could spatially interact with

safety related equipment but are not physically connected to a safety related system. The

applicant stated that it considered the following types of nonsafety related spatial interactions

during scoping:

* physical impact, such as in a seismic event

* pipe whip

* jet impingement

* harsh environment resulting from a piping rupture

* damage resulting from leakage, spray, or flooding

The applicant described the use of both mitigative and preventive approaches for scoping

nonsafety related equipment in the LRA. The mitigative approach relied upon installed

protective features (i.e., whip restraints, spray'shields, supports, barriers) to protect safety

related SSCs against spatial interaction with nonsafety related SSCs. The applicant stated that

such protective features credited in the plant design are within the scope of license renewal

based on the criteria of 10 CFR 54.4(a)(2). In thjose cases in which protective features provide

adequate protection, the applicant excluded norisafety related SSCs from the scope of license

renewal. The applicant stated that nonsafety related SSCs that provide flood barriers to safety

related SSCs (i.e., walls, curbs, dikes, or doors) are within the scope of license renewal based

on the criteria of 10 CFR 54.4(a)(2). Additionally, the applicant stated that inherent nonsafety

related features that protect safety related equipment from missiles generated from internal or

external events are within the scope of license renewal based on the 10 CFR 54.4(a)(2)'criteria.

In Section 2.1.1.2.2 of the LRA, the applicant described how the scoping process considered

the impact on falling equipment from load handling malfunctions and failed piping segments.

The LRA stated that overhead-handling systems from which a load drop could result in damage

to any system that could prevent the accomplishment of a'safety related function are within the

scope of license renewal based on the criteria of 10 CFR 54.4(a)(2).- However, the applicant

concluded that (1) no earthquake experience data exist of welded steel pipe segments falling as

a result of a strong motion earthquake, and (2) falling of piping segments is extremely rare and

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only occurs when there is a pipe support failure. The applicant therefore concluded that, as

long as the effects of aging on the supports for welded steel piping systems were managed,

falling sections of piping are not a credible scenario. Consequently, although the applicant

considered the effects of spray and leakage, it did not consider the piping section to be within

scope for 10 CFR 54.4(a)(2) because of the physical impact hazard.

The applicant concluded that spatial interactions of pipe whip, jet impingement, and harsh

environment are credible only for high-energy systems. Therefore, the applicant stated that, if a

high-energy line break (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 based on the criteria of 10 CFR 54.4(a)(2) and is subject to an AMR to

provide reasonable assurance that those assumptions remain valid throughout the period of

extended operation. The applicant noted that moderate- and 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 required safety functions are considered

within the scope of license renewal based on the 10 CFR 54.4(a)(2) criteria. However, the LRA

states that long-term exposure to conditions resulting from a failed nonsafety related SSC (such

as leakage or spray) are not considered credible. The applicant stated that it would detect

leakage or spray from liquid-filled low-energy systems during routine operator rounds or system

walkdowns before such leakage or spray could impact the performance of safety related

equipment. Followup actions would direct leakage away from equipment to prevent failure, and

the applicant will perform evaluations of the condition of the piping.

The applicant stated that operating experience indicates that nonsafety related systems

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

ability of safety related equipment to perform required safety functions. Consequently, the

applicant determined that air and gas (nonliquid) systems are not a hazard to other plant

equipment and that these systems are not within the scope of license renewal based on the

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

Application of the Scoping Criteria in 10 CFR 54.4(a)(3). In Sections 2.1.1.3, "Application of

Criterion for Regulated Events," and 2.1.3, "Interim Staff Guidance Discussion," of the LRA, the

applicant discussed the methodology used to identify SSCs credited for performing a function

that demonstrates compliance with regulations for fire protection (FP), environmental

qualification (EQ), pressurized thermal shock (PTS), anticipated transients without scram

(ATWS), and station blackout (SBO) pursuant to the 10 CFR 54.4(a)(3) license renewal scoping

criteria. The following sections describe the applicant's approaches for scoping systems and

structures required to mitigate each of these five regulated events.

Fire Protection

The applicant described the scoping of SSCs required to demonstrate compliance with the FP

requirements of 10 CFR 50.48 in Section 2.1.1.3.1, "Fire Protection (10 CFR 50.48)," of the

LRA. The applicant stated that it performed a detailed review of the current licensing basis

(CLB) for FP. The applicant placed SSCs credited with fire prevention, detection, and

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

scope of license renewal, and the applicant identified the associated intended functions on

which it relied.

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Environmental Oualification

The applicant described the scoping of SSCs required to demonstrate compliance with the EQ

requirements of 10 CFR 50.49 in LRA Section 2.1.1.3.2, "Environmental Qualification

(10 CFR 50.49)." Electrical equipment important to safety that is required to be environmentally

qualified to mitigate certain accidents that would result in harsh environmental conditions in the

plant is defined in 10 CFR 50.49. The applicant stated that, because it used a bounding

approach for electrical equipment scoping, it included all electrical systems and electrical

equipment in mechanical systems within the scope of license renewal. Consequently,' the

applicant concluded that all environmentally qualified equipment is within the scope of license

renewal based ib tge criteria of 10 CFR 54.4(a)(3).

Pressurized Thermal Shock

The applicant described the scoping of SSCs required to demonstrate compliance with the PTS

requirements of 10 CFR 50.61 in Section 2.1.1.3.3, "Pressurized Thermal Shock

(10 CFR 50.61)," of the LRA. The applicant stated that the only system relied upon to meet the

PTS regulation is the reactor coolant system (RCS), which contains the reactor vessel.

Furthermore, the applicant concluded that it did not rely upon any structures to meet the

requirements of 10 CFR 50.61.

Anticipated Transients Without Scram

The applicant described the scoping of SSCs required to demonstrate compliance with the

ATWS requirements of 10 CFR 50.62 in Section 2.1.1.3.4, "Anticipated Transients without

Scram (10 CFR 50.62)," of the LRA. The applicant stated that, based on a review of the CLB

for ATWS, it determined the intended functions supporting the 10 CFR 50.62 requirements.

The applicant noted that the plant systems supporting compliance with the requirements of

10 CFR 50.62 are primarily electrical and l&C systems. However, the applicant indicated that

the intended function for the main turbine (MT) also supports 10 CFR 50.62 requirements.

Station Blackout

The applicant described the scoping of SSCs required to demonstrate compliance with the SBO

requirements of 10 CFR 50.63 in Section 2.1.1.3.5, "Station Blackout (10 CFR 50.63)," of the

LRA. The applicant noted that the scope of equipment relied upon to support 10 CFR 50.63 is

that required to ensure that the reactor core is cooled and containment integrity is maintained

during the 4-hour coping duration before offsite or onsite alternating current (ac) power is

restored. The applicant stated that, based on the review of the CLB for SBO, it identified the

equipment performing intended functions required for compliance with 10 CFR 50.63.

2.1.2.1.2 Documentation Sources Used for Scoping and Screening

In Section 2.1.1, "Scoping Methodology," of the LRA, the applicant described the information

sources reviewed during the license renewal scoping and screening process. The applicant

stated that the key information sources that form' the CLB for the CNP include the updated final

safety analysis report (UFSAR), technical specifications, and docketed licensing -

correspondence. The applicant noted that it used these CLB documents, as well as the

following information sources, to identify the systems and structures list:

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* The facility database (FDB) contains records of component and equipment items for

which the safety related status and procurement grades have been determined and

verified. In addition to identifying the component name, unique identification number,

and safety classification, FDB records also include information pertaining to plant

maintenance and operation.

* The applicant used civil/structural plant layout drawings.

Functions for structures and mechanical systems were identified based on reviews of CLB

documentation and other information sources, including the following:

* The Maintenance Rule Program database describes the systems and system functions

to demonstrate that the SSCs scoped into the Maintenance Rule are monitored in

accordance with 10 CFR 50.65. The database also includes the Maintenance Rule

scoping documents. The applicant used the Maintenance Rule systems and functions

as part of the starting point in the scoping effort.

* The Expanded System Readiness Review (ESRR) program assessed the conformance

of the plant design, testing, maintenance, operation, and configuration with the licensing

and design-basis requirements. The applicant used the ESRR reports as a resource for

system descriptions and identification of SSC functions.

The applicant stated that the intent of the document review was to identify all major system

functions to provide reasonable assurance that all license renewal functions were identified.

2.1.2.1.3 System, Structure, and Component Level Scoping

In Sections 2.1.1, "Scoping Methodology," and 2.1.2, "Screening Methodology," of the LRA, the

applicant described the scoping methodology for systems and structures that are safety related,

nonsafety related, or relied upon to perform a function to demonstrate compliance with the

regulated events described in 10 CFR 54.4(a)(3). The applicant considered scoping as the

process of identifying systems and structures that perform a license renewal intended function.

The licensee did not describe a component-level scoping process in the LRA, but instead

performed a component-level scoping as an integral part of the screening process.

As its starting point for the scoping process, the applicant created a list of systems and

structures using the CLB and other information sources. After creating the system and

structure list and identifying associated functions, the applicant then determined which systems

and structures perform license renewal intended functions. In the LRA, the applicant described

the different approaches it used to scope mechanical systems, electrical and l&C systems, and

structures in accordance with 10 CFR 54.4(a). The sections below describe the scoping

methodology for each of these component classifications.

Mechanical System and Component Scoping Methodology. As described in Section 2.1.1 of

the LRA, the applicant determined which of those functions performed by plant mechanical

systems meet any of the three criteria of 10 CFR 54.4(a). Functions that meet any of the

10 CFR 54.4(a) scoping criteria are considered intended functions for license renewal, and the

applicant included systems that performed these intended functions within the scope of license

renewal. Although the applicant's scoping methodology as described in the LRA does not show

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a process for scoping individual mechanical components, Section 2.1.2.1, "Screening of

Mechanical Components," of the LRA states that, for each mechanical system within the scope

of license renewal, the screening process identified those components subject to an AMR. To

determine which components are subject to an AMR, the applicant identified system evaluation

boundaries to show those portions of the mechanical system necessary to ensure that the

intended functions of the system would be performed. As described in Section 2.1.2.1.1,

"Determining Evaluation Boundaries," of the LRA, the applicant included components needed to

support each of the system-level intended functions identified in the scoping process within the

system evaluation boundary. The applicant stated that the determination of the system

evaluation boundary required an understanding of system operations in support of the intended

functions. This process was based on the CLB, plant-specific experience, appropriate industrywide operating experience, and design documents (e.g. calculations, drawings).

Structure and Structural Component Scoping Methodology. As described in Section 2.1.1 of

the LRA, the applicant determined those functions performed by plant structures which meet

the scoping criteria of 10 CFR 54.4(a). The applicant considered functions that met any of the

10 CFR 54.4(a) scoping criteria as intended functions for license renewal and included the.

associated structure within the scope of license renewal. As described in Section 2.1.2.2.3,

"Intended Function," of the LRA, 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.

Although the applicant's scoping methodology as described in the LRA does not describe a

process for scoping individual structural components, Section 2.1.2.2, "Screening of Structural

Members and Components," of the LRA states that, for each structure within the scope of

license renewal, the screening process identified components and commodities subject to an

AMR. The applicant stated that the screening process for structural components and

commodities involved a review of design documents (i.e., UFSAR and drawings) to identify

specific structural components and commodities that constitute the structure. The applicant

then categorized structural components and commodities with no unique identifiers into

groupings based on materials of construction.

Electrical and Instrumentation and Control System and Component Scoping Methodology. The

applicant described the methodology used to scope electrical and l&C systems in Section 2.1.1,

"Scoping Methodology," Section 2.1.2.3,- Screening of Electrical and Instrumentation and

Control Components," and Section 2.5, "Scoping And Screening Results: Electrical and

Instrumentation and Control Systems," of the LRA. The applicant stated that it used a bounding

scoping approach for electrical equipment. Using this approach, the applicant included plant

electrical and l&C systems, as well as electrical and l&C components in mechanical systems,

within the scope of license renewal. Under this scoping approach, the applicant did not

consider system-level intended functions of electrical and l&C components.

The applicant stated that it grouped the total population of electrical components into

commodity groups that included electrical and l&C components with common characteristics.

The applicant then identified component-level intended functions of these commodity groups.

The applicant subjected the electrical commodity groups to further screening to identify

component types subject to an AMR.

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2.1.2.2 Screening Methodology

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

implemented a process for determining which SSCs would be 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 stated that the screening process for a structure or component within the

scope of license renewal determined the following:

* whether the structure or component performs a component intended function without

moving parts and without a change in configuration or properties (i.e., it is passive)

* whether the structure or component is not subject to replacement based on a qualified

life or specified time period (i.e., it is long-lived)

Screening activities identified mechanical, structural, and electrical and l&C components within

the scope of license renewal and subject to an AMR. The following describes the applicant's

screening methodology identified in the LRA for mechanical, structural, and electrical and l&C

components.

2.1.2.2.1 Mechanical Component Screening

Following mechanical system scoping, the applicant performed screening to identify those

mechanical components that are subject to an AMR. The applicant stated in LRA Section

2.1.2.1.2, "Identifying Components Subject to Aging Management Review," that 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. Additionally, the applicant stated

that, in the case of valves, pumps, fans, and dampers, the valve bodies, pump casings, and

housings for fans and dampers perform an intended function by maintaining the pressure

boundary and are therefore subject to an AMR.

If the mechanical component is not subject to replacement based on a qualified life or specified

time period, the applicant considered it long-lived. As stated in the LRA, component

replacement programs are based on vendor recommendations, plant experience, or any means

that establishes a specific service life, qualified life, or replacement frequency under a

controlled program.

The applicant created license renewal drawings to indicate on mechanical flow diagrams those

components within the system evaluation boundaries requiring an AMR. However, the

applicant noted that the drawings do not generally include components within the scope of

license renewal based solely on the criterion of 10 CFR 54.4(a)(2).

2.1.2.2.2 Structural Component Screening

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

those structural components that are subject to an AMR. In Section 2.1.2.2, "Screening of

Structural Members and Components," of the LRA, the applicant described the methodology

used to screen structural components. The applicant stated 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

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-

replacement based on qualified life or specified time period (i.e., long-lived). The applicant

noted that, since structures are inherently passive, and with few exceptions are long-lived, it

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

perform an intended function.

2.1.2.2.3 Electrical and Instrumentation and Control Component Screening

In Sections 2.1.2.3 and 2.5 of the LRA, the applicant described the methodology used to screen

electrical and l&C components. The applicant stated in Section 2.1.2.3.3, "Long-Lived

Screening," that electrical components included in the Environmental Qualification Program

pursuant to 10 CFR 50.49 are replaced based on a qualified life. As such, they do not meet the

"long-lived" criterion of 10 CFR 54.21 (a)(1 )(ii) and are not subject to an AMR. Therefore, the

applicant concluded that AMRs involve only non-EQ electrical and l&C components.

In Section 2.1.2.3.2, "Passive Screening," of the LRA, the applicant noted that it crossreferenced electrical commodity groups to the appropriate NEI 95-10 commodity to identify the

passive commodity groups. The applicant identified two passive electrical and l&C commodity

groups that meet the 10 CFR 54.21 (a)(1 )(i) criterion (i.e., components performing an intended

function without moving parts or without a change in configurationr)-(1) cables and

connections, bus, electrical portions of electrical and l&C penetration assemblies and (2) highvoltage insulators. The applicant concluded that other electrical and l&C commodity groups are

active and not subject to an AMR.

2.1.2.2.4 Commodity Group Component Screening

In Section 2.1.2.4, "Identification of Short-Lived Components and Consumables," of the LRA,

the applicant described the generic screening results for several types of short-lived

components and consumables. The applicant determined that consumables and short-lived

components, such as packing, gaskets, component seals, and O-rings; oil, grease and filters;

fire extinguishers, fire hoses, and air packs are not subject to an AMR.

2.1.3 Staff Evaluation

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

guidance contained in Section 2.1, "Scoping and Screening Methodology," of NUREG-1 800,

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

issued July 2001 (hereafter referred to as the SRP-LR). The staff based the acceptance

criteria for the scoping and screening methodology review on the following regulations:

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

rule

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

determined to be within the scope of the rule

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

identify plant structures and components subject to an AMR

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II

As part of the review of the applicant's scoping and screening methodology, the NRC staff

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

SRP-LR:

* Section 2.1, "Scoping and Screening Methodology," to ensure that the applicant

described a process for identifying SSCs within the scope of license renewal in

accordance with the requirements of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and

10 CFR 54.4(a)(3)

* Section 2.2, "Plant-Level Scoping Results"; Section 2.3, "Scoping and Screening

Results: Mechanical Systems"; Section 2.4, "Scoping and Screening Results:

Structures"; and Section 2.5, "Scoping and Screening Results: Electrical and

Instrumentation and Control Systems," to assure the applicant described a process for

determining structural, mechanical, and electrical components at the CNP that are

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

10 CFR 54.21 (a)(2)

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

Michigan Power Company (I&M) engineering offices in Buchanan, Michigan, from January

13-16, 2004. 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 described in the application and the requirements of 10 CFR Part 54. The staff

reviewed implementation procedures and engineering reports which describe the scoping and

screening methodology that the applicant implemented. In addition, the staff conducted

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

program. The staff also reviewed administrative control documentation and selected design

documentation that the applicant used during the scoping and screening process. The staff

further reviewed a sample of system scoping and screening results reports for the ice

condenser, auxiliary feedwater, emergency core cooling, and main feedwater systems to

ensure that the applicant appropriately implemented the methodology outlined in the

administrative controls and that the results are consistent with the CLB. The staff documented

its review in an audit report issued on September 8, 2004. The report identified several issues

which required additional information from the applicant prior to completion of the review effort.

Each of these issues is identified and addressed in detail in Section 2.1 of this safety

evaluation.

2.1.3.1 Scoping Methodology

The staff reviewed the scoping process to verify the consistency of the applicant's methodology

with the SRP-LR and other documented staff positions and that the scoping methodology

adequately identified SSCs within the scope of license renewal, in accordance with the

requirements of 10 CFR 54.4(a).

2.1.3.1.1 Implementation Procedures and Documentation Sources Used for Scoping and

Screening

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

that the process used to identify SCs subject to an AMR is consistent with the LRA and the

SRP-LR and that the applicant appropriately implemented the procedural guidance.

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Additionally,-the staff reviewed the scope of CLB documentation sources used to support the

LRA development and the process the applicant used to ensure that CLB commitments were

appropriately considered during the scoping and screening process.

Scoping and Screening Implementation Procedures. The staff reviewed the following scoping

and screening methodology implementation procedures and engineering reports:

* License Renewal Project Guideline (LRP-PG)-01, "Scoping Systems and Structures"

* LRP-PG-02,- License Renewal Program Plan'

* LRP-PG-03, "Structural Screening and Aging Management Reviews"

* -LRP-PG-04, "Mechanical System Screening and Aging Management Reviews"

* LRP-PG-05, "Electrical System Scoping,- Screening and Aging Management Reviews"

* LRP-PG-1 4, "10 CFR 54.4(a)(2) Nonsafety related SSC Affecting Safety related SSC"

* License Renewal Project Mechanical Aging Management Report (LRP-MAMR)-35,

"Aging Management Review of Nonsafety related Systems and Components Affecting

Safety related Systems"

In reviewing these procedures, the staff focused on the consistency of the detailed procedural

guidance with information in the LRA and the various NRC staff positions documented in the

SRP-LR and ISG documents. The staff found that the applicant's scoping and screening

methodology instructions and procedures are generally consistent with Section 2.1 of the LRA

and are of sufficient detail to provide the applicant's staff with consistent guidance on the

scoping and screening implementation process to be followed during the LRA activities.

Quality Assurance Controls Applied to LRA Development. The staff reviewed the quality

assurance (QA) controls used by the applicant to provide reasonable confidence that the LRA

scoping and screening methodologies were adequately implemented. The applicant utilized the

following QA processes during the LRA development:

* Implementation of the scoping and screening methodology was governed by written

procedures and guidelines.

* Although much of the LRA development was performed by contractors, the applicant

developed procedures to govern the conduct of owner acceptance reviews of contractor

work products. For example, License Renewal Project Guideline LRP-PG-12, "Owner's

Acceptance Reviews," describes the process used by the applicant to review license

renewal project documents provided by Framatome/Entergy. Documents subject to this

acceptance review included AMR reports, time-limited aging analyses (TLAAs), and

aging management program (AMP) evaluation reports.

* -The Nuclear Safety Review Board and the Plant Operations Review committee reviewed

and approved the LRA before the applicant submitted it to the NRC. Additionally, the

applicant developed procedural guidance for a final review of the LRA prior to submittal

to the NRC. :

* The applicant planned to retain certain license renewal documents, such as aging

-management reports,- individual system scoping reports, time-limited aging analyses,

and topical reports, as quality records.

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The applicant performed a peer review and two self assessments of license renewal

activities.

The staff concluded that these QA activities, which exceed current regulatory requirements,

provide additional assurance that the applicant performed the LRA development activities in a

manner consistent with the LRA descriptions.

Training for License Renewal Proiect Personnel. The staff reviewed the applicant's

implemented training process to ensure that the guidelines and methodology for the scoping

and screening activities would be performed in a consistent and appropriate manner. The staff

found the training of the license renewal project team to be incremental, iterative, and adapted

to the needs of the tasks to be performed. Initially, a core group of three persons was trained

by being required to read a family of documents and certify that they had done so. That family

of 28 documents is listed in Attachment 6, "Training Requirements," to LRP-PG-02, "License

Renewal Program Plan." The second group of personnel trained were subject matter experts.

Everyone working on the license renewal project was given, at a minimum, overview-level

training. Trainees numbered about 100, including American Electric Power (AEP) employees,

contractors working directly on the project, and Framatome and Entergy subcontractors.

Formal classroom training from 2 to 8 hours was provided; for example, the former was

provided to managers, the latter, to in-depth participants. The training focused on the level

necessary to perform assigned tasks. The training requirements were categorized in the LRPPG-02 training requirements matrix pursuant to license renewal project personnel who prepared

or reviewed various documents, such as scoping documents, AMRs, program evaluations,

TLAAs, and the LRA, and among site personnel who reviewed or approved those documents.

Completed training was documented on individual "License Renewal Training Documentation"

forms, also from Attachment 6 to LRP-PG-02. Periodic meetings were held with various system

owners to provide understanding of issues and proposed solutions. The staff interviewed LRA

team members and concluded they were very knowledgeable of requirements and activities

associated with scoping and screening.

On the basis of its discussions with the applicant's license renewal project team responsible for

the scoping and screening process, as well as a review of selected design documentation in

support of the process, the staff concluded that the applicant's staff understood the

requirements of the scoping and screening methodology and adequately implemented such

methodology in the renewal application. The staff did not identify any significant concerns

regarding the training of the applicant's license renewal project team or contractors.

Sources of Current Licensing Basis Information. The staff reviewed the scope and depth of the

applicant's CLB review to verify that the methodology was sufficiently comprehensive to identify

SSCs within the scope of license renewal and SCs requiring an AMR. As defined in

10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a specific plant and a

licensee's written commitments for ensuring compliance with and operation within applicable

NRC requirements and the plant-specific design basis that are docketed and in effect. The

CLB includes certain NRC regulations, orders, license conditions, exemptions, technical

specifications, design-basis information documented in the most recent final safety evaluation

report (SER), and licensee commitments remaining in effect that were made in docketed

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

enforcement actions, as well as licensee commitments documented in NRC safety evaluations

or licensee event reports (LERs).

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The staff determined that Section 2.1.1 of the LRA provides a description of the CLB and

related documents used during the scoping and screening process that is consistent with the

guidance contained in the SRP-LR and NEI 95-10. Specifically, Section 2.1.1 of the LRA

identifies the UFSAR, technical specifications, docketed licensing correspondence, the Facility

Database (FDB), plant layout drawings, the Maintenance Rule database, and ESRR reports, as

information sources used during scoping. Additionally, in Section 5.4 of scoping

implementation procedure LRP-PG-01, the applicant provided a comprehensive listing of

documents that it could use to support scoping and screening evaluations. The applicant

identified system functions based on its review of the applicable sections of the UFSAR,

technical specifications, Maintenance Rule scoping document, initial and final ESRR reports,

design-basis documents (DBDs), and license renewal topical reports. During the methodology

audit, the applicant stated that, although some of these documents are not considered to be a

part of the CLB (such as the Maintenance Rule scoping documents, ESRR reports, and DBDs),

it used them to identify potential CLB functions and additional CLB references.

The CNP FDB is the applicant's primary repository for component safety classification

information. During the audit, the staff reviewed the applicant's administrative controls for FDB

safety classification data and concluded that the applicant had established adequate measures

to control the integrity and reliability of FDB safety classification data. Therefore, the staff

concluded that the FDB provides a sufficiently controlled source of component data to support

scoping and screening evaluations.

In the LRA, the applicant showed topical reports as a source of information to support --

identification of systems and structures relied upon to demonstrate compliance with the five

regulated events referenced in 10 CFR 54.4(a)(3). Procedure LRP-PG-06, "License Renewal

Topical Reports," provides guidance for preparing, reviewing, issuing, and maintaining topical

reports. Procedure LRP-PG-06 also identifies a listing of potential CLB information sources

that is consistent with Section 2.1.1 of the LRA. Additionally, LRP-PG-06 includes specific

guidance for the format and content of a topical report, report review, and approval.- The

inspectors concluded that LRP-PG-06 provides sufficient guidance to reasonably ensure that

topical reports adequately summarize CLB information for the purposes of scoping.

In addition to the sources referenced above, the applicant used its corrective action database to

review site-specific operating experience. -Since mid-1 997, the applicant maintained an

electronically searchable condition report (CR) database. By performing keyword searches of

the CR database, the applicant identified pertinent site-specific operating experience within the

Corrective Action Program. Although the database may not include CRs written before mid1997, the staff determined that the use of the CR database, in combination with other data

sources, including CLB documents and ESRR reports, provides reasonable assurance that the

applicant adequately considered site-specific operating experience during scoping and

screening evaluations.

Conclusion

Based on a review of information provided in Section 2.1 of the LRA, a review of the applicant's

detailed scoping and screening implementation procedures, and the results from the scoping

and screening audit, the staff concluded that the applicant's scoping and screening

methodology considered a sufficient scope and depth of CLB information. The staff determined

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that the CLB documentation review methodology is capable of identifying SSC intended

functions in a manner consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21.

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

The staff evaluated the applicant's methodology for scoping safety related and nonsafety

related SSCs and SSCs relied upon to demonstrate compliance with regulated events pursuant

to the requirements of 10 CFR 54.4(a). The following describes the results of this staff

evaluation.

Application of the Scoping Criteria in 10 CFR 54.4(a)(1). Pursuant to 10 CFR 54.4(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 (DBEs) to ensure:

(1) the integrity of the reactor coolant pressure boundary (RCPB), (2) the ability to shut down

the reactor and maintain it in a safe-shutdown condition, or (3) the capability to prevent or

mitigate the consequences of accidents 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.

With regard to identifying DBEs, Section 2.1.3, "Review Procedures," of the SRP-LR, states the

following:

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

(or equivalent) of the UFSAR. Examples of design basis events that may not be

described in this chapter include external events, such as floods, storms,

earthquakes, tornadoes, or hurricanes, and internal events, such as a highenergy-line break.

During the audit, the NRC staff questioned how the applicant considered nonaccident DBEs

during scoping, particularly DBEs that may not be described in the UFSAR. The applicant

identified the DBEs applicable to CNP, including external hazards such as fire, earthquakes,

flooding, wind and missiles, and HELBs. The staff concluded that the applicant considered a

scope of DBEs consistent with the guidance contained in the SRP-LR.

The applicant performed scoping of safety related SSCs in accordance with the implementation

Sections 5.2 and 5.4 of procedure LRP-PG-01. The applicant classified SSCs as either safety

related or nonsafety related using the safety classification field in the FDB. Section 5.2 of LRPPG-01 requires that the applicant review the FDB safety classification field to ensure that any

system or structure that has a component identified as safety related is considered for inclusion

in the scope of the license renewal project. The staff reviewed the safety classification criteria

used to determine the FDB safety classification to verify consistency with the 10 CFR 54.4(a)(1)

criteria. The staff determined that the nuclear safety related definition the applicant used in its

safety classification program does not include all the exposure limitations referenced in

10 CFR 54(a)(1)(iii). Specifically, CNP Procedure 12-EHP-5043-SCD-001, "Safety

Classification Determinations," does not include a reference to the offsite exposure limitations in

10 CFR 50.67(b)(2) for use of an alternate source term (AST).

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RA12.1-1

In discussions with the CNP license renewal project team, the NRC staff noted that the

applicant previously submitted a license amendment application to allow use of the AST

methodology for control room habitability dose analyses. The staff subsequently approved use

of the AST for control room habitability dose evaluations. At the time of the audit, the applicant

had not decided to pursue an amendment for use of the AST methodology for offsite dose

evaluations. Therefore, in Request for Additional Information (RAI) 2.1-1, the staff asked the

applicant to describe how it factored the use of the AST methodology for control room operator

dose into its scoping evaluations. In particular, the staff requested that the applicant identify the

impact of the alternate source methodology on the scoping of safety related SSCs pursuant to

10 CFR 54.4(a)(1). Additionally, with regard to the potential future use of the AST methodology

for offsite dose analysis, the staff requested that the applicant describe its plans for evaluating

the license renewal scoping impact should it request a future license amendment to use the

AST methodology for offsite dose analysis.

The applicant responded to RAI 2.1-1 in a letter dated May 7, 2004. The applicant stated that

the use of the AST method, as approved in the Unit 1 License Amendments 258 and 271 and

Unit 2 License Amendments 241 and 252, does not impact the scoping of safety related SSCs

pursuant to 10 CFR 54.4(a)(1). The use of the AST methodology affects operating limits and

analysis input parameters, which in turn affects some equipment performance requirements.

However, the applicant stated that the AST methodology did not establish any new equipment

functional requirements in that no new or different equipment is credited for the revised control

room dose analyses, and no new or different operational modes are required of equipment

already credited in the analyses. Furthermore, the applicant stated that, if it shbuld pursue a

license amendment to apply the AST methodology to offsite dose analysis in the future, it will

evaluate any changes to equipment functional requirements that would result from the new,

analyses in accordance with established design control processes.- If an additional license

amendment regarding AST should occur before issuance of a renewed operating license, the

applicant stated that it will evaluate the resultant changes to the CLB and determine if they

materially affect the contents of the LRA, and if so, address them in accordance with the -

requirements of 10 CFR 54.21 (b). The staff concluded that the applicant adequately addressed

the staff's concern regarding the use of the AST methodology during scoping evaluations. In

particular, the staff determined that the applicant adequately considered the impact of the AST

methodology on safety related scoping evaluations conducted pursuant to 10 CFR 54.4(a)(1).

On this basis, RAI 2.1-1 is resolved.,

RAI2.1-2

The applicant's scoping guidance noted that a system or structure may not perform an

10 CFR 54.4(a)(1) intended function even though the system or structure is classified as safety

related for plant-specific purposes. In these cases, LRP-PG-01 allows the applicant to exclude

the SSC from the scope of safety related SSCs considered under license renewal. However,

LRP-PG-01 states that the applicant must still evaluate the SSC for inclusion within the scope

of license renewal under the criteria in 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3). During the

audit, the staff reviewed the process that the applicant used to evaluate components classified

as safety related in the FDB that did not perform a safety related license renewal intended

function. The applicant reevaluated the FDB safety-classification of many safety related

components to reconcile differences between license renewal scoping determinations and FDB

2-15
11,

information. In RAI 2.1-2, the staff requested that the applicant describe the process used to

evaluate components classified as safety related that were determined not to perform a safety

related intended function. In particular, the staff requested the following:

(1) The applicant should describe 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.

(2) In reviewing the scoping results for the component cooling water (CCW) system, the

staff identified that the applicant did not include several safety related components on

the miscellaneous cooling header within the scope of license renewal. Therefore, the

staff requested a description of how the applicant addressed components originally

classified as safety related in the CCW miscellaneous header during scoping

evaluations.

(3) The applicant should describe the process used to reconcile the FDB safety

classification information with scoping intended function determinations. In particular,

the staff requested additional information about the scope of the review used to

reevaluate the safety-classification of SSCs to reconcile disparities with intended

function determinations.

The applicant responded to RAI 2.1-2 by letter dated May 7, 2004. In its response, the

applicant noted that the scoping process identified some passive, long-lived mechanical

components (mostly small valves) classified in the FDB as safety related that do not appear to

perform a safety related support function. However, the applicant noted that the FDB is not

used as the primary basis for inclusion of components subject to aging management; rather it is

used as a tool to confirm that all components with a safety related function are properly and

correctly subjected to an AMR. To reconcile differences between scoping conclusions and FDB

information, the applicant stated that it wrote Corrective Action Program condition reports to

track safety classification determinations (SCDs) and the FDB updates. In its RAI response,

the applicant also described the process used to revise the safety classification information in

the FDB. The applicant stated that plant procedures control revisions to FDB safety

classification information and include a review of design documents describing the functions

and the safety classification of the component.

In February 2003, after completion of the AMR reports, the applicant performed a

comprehensive comparison of the mechanical components classified as safety related in the

FDB but not subject to an AMR to those components (thermowells, valves, and conoseals) that

are subject to an AMR. The applicant subsequently included these additional components in

the AMR reports, as applicable. The applicant also stated that SSCs classified as safety

related in the FDB that do not perform a safety related license renewal intended function are

generally identified in the Corrective Action Program for further evaluation under the SCD

process.

The applicant performed a similar comparison in January 2004. The applicant stated that the

January 2004 comparison identified a few passive, long-lived mechanical components

associated with the CCW system miscellaneous header that do not perform a safety related

intended function but have not been reclassified from safety related to nonsafety related.

However, the applicant noted that these CCW system components are subject to an AMR for

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10 CFR 54.4(a)(2) considerations. .Additionally,-the applicant stated that the January 2004

comparison identified a small number of system components classified as safety related in the

FDB (typically valves, thermowells, flex hoses, and dampers) in several systems that do not

perform a safety related intended function as defined in 10 CFR 54.4(a)(1). In its RAI

response, the applicant identified these specific component types and provided a basis for the

conclusion that they do not perform a safety related intended function. The applicant stated

that it conservatively classified these components as safety related in the FDB and may

consider them for future safety classification downgrades. However, in some cases, the

applicant noted that these components may perform' an intended function as defined under

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

summary, the applicant concluded that it found all long-lived, passive mechanical components

that perform a 10 CFR 54.4(a)(1) intended function to be subject to an AMR.

The staff concluded that the applicant provided an adequate basis for its determination that

certain equipment classified as safety related in the FDB does not perform a safety related

intended function. In particular, the staff noted that the applicant performed two comparison

reviews to identify safety related equipment that may have been omitted from the scoping

process, tracked discrepancies between scoping determinations and the FDB in the Corrective

Action Program, and systematically revised FDB safety-classification data. The staff -

determined that these measures provided reasonable assurance that SSCs performing a safety

related intended function pursuant to 10 CFR 50.54(a)(1) are included within the scope of

license renewal. On this basis, RAI 2.1-2 is resolved.

The applicant implemented the safety related scoping process through the use of a system

function scoping question checklist. In accordance with Section 5.4 of LRP-PG-01, for each

identified system or structure function the applicant asked safety related scoping questions

pursuant to a scoping checklist to determine if the function met the scoping criteria of

10 CFR 54.4(a)(1). The staff reviewed the safety related scoping questions and concluded that

they are consistent with the requirements of 10 CFR 54.4(a)(1).

To provide additional assurance that the applicant adequately implemented its safety related

scoping methodology, the NRC methodology staff reviewed a sample of the license renewal

scoping results for the ice condenser, auxiliary feedwater, emergency core cooling, and main

feedwater systems. The staff concluded that the applicant adequately implemented its

10 CFR 54.4(a)(1) scoping process. Additionally, the staff determined that the applicant

identified and used pertinent engineering and licensing information to support the scoping

determinations for the items sampled.

Conclusion. On the basis of a review of the applicant's methodology and evaluation of a

sampling of scoping results, the staff concluded that the applicant's safety related scoping

methodology provides reasonable assurance that the applicant included SSCs meeting the

scoping criteria of 10 CFR 54.4(a)(1) within the scope of license renewal. Specifically, the staff

concluded that the applicant considered an adequate set of DBEs and used reasonable

methods for identifying safety related intended functions.

Application of the Scoping Criteria in 10 CFR 54.4(a)(2). As required by 10 CFR 54.4(a)(2), the

applicant must consider all nonsafety related SSCs, the failure of which could prevent

satisfactory accomplishment of any safety related functions identified in 10 CFR .54.4(a)(1), to

be within'the scope of license renewal. As described in the SRP-LR, the applicant must identify

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IL 1'1

those nonsafety related SSCs (including certain support systems) failures of which are considered in the CLB and could prevent accomplishment of the safety related functions

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

The staff provided further expectations for determining what SSCs meet the 10 CFR 54.4(a)(2) criterion in letters dated December 3, 2001, and March 15, 2002. In the December 3, 2001 letter, the staff describes the expectation that both seismic 11/I piping segments and their supports should be included within the scope of license renewal under the 10 CFR 54.4(a)(2) criterion. Additionally, the 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 in scope based on the 10 CFR 54.4(a)(2) criterion. The March 15, 2002 letter further describes the staff's expectations regarding how the applicant should determine which nonsafety related SSCs could adversely impact intended functions and therefore be within the scope of license renewal. The staff's position states that applicants should not consider hypothetical failures; rather, applicants should base their evaluation on the plant's CLB, engineering judgment and analyses, and relevant operating experience. The letter further describes operating experience as all documented plant-specific and industrywide experience which can be used to determine the plausibility of a failure. Documentation would include NRC generic communications and event reports, plant-specific CRs, industry reports such as significant operating event reports, and engineering evaluations.

The applicant documented its methodology for performing 10 CFR 54.4(a)(2) scoping of nonsafety related SSCs in implementation procedures LRP-PG-01, LRP-PG-14, and LRP-MAMR-35. The applicant performed nonsafety related license renewal scoping in a two- stage process. The first stage of the process considered nonsafety related equipment that either provided a support function to a safety related intended function or was directly attached to a safety related system. The second stage of the process, which considered spatial interactions between nonsafety related equipment and safety related SSCs, addressed the staff expectations described in the December 3, 2001 and March 15, 2002 guidance letters. During the second stage of 10 CFR 54.4(a)(2) scoping, the applicant considered spatial interactions, including leakage, spray, and flooding; physical impact; and pipe whip, jet impingement, or harsh environments. The remainder of this section describes the applicant's approach for addressing each of these 10 CFR 54.4(a)(2) scoping aspects.

Nonsafety related Support Equipment

Scoping methodology implementing procedure LRP-PG-01, Section 5.3, states that nonsafety related systems and structures that directly support the function of a safety related system or structure, or the failure of which could prevent the performance of a safety related function, are within the scope of license renewal. Scoping implementation procedure LRP-PG-01 notes that the plant's CLB, actual plant-specific operating experience, industrywide operating experience, and existing plant-specific engineering evaluations should be considered to determine the appropriate systems and structures meeting the criteria of 10 CFR 54.4(a)(2). This methodology approach is consistent with Section 2.1.1.2.1 of the LRA, which states that for the cases in which nonsafety related equipment is required to remain functional in support of a safety function, the supporting systems are included within the scope of license renewal. The staff concluded that the applicant considered an adequate scope of CLB information and

2-18
implemented a reasonable approach for scoping of nonsafety related SSCs that provide

support functions to safety related intended functions.

Nonsafety related Piping Attached to Safety related SSCs

In the SRP-LR, Section 2.1.3.1.2 indicates instances in which an entire pipe run containing both

safety related and nonsafety related piping and associated piping anchors may have been

analyzed as part of the CLB to establish that it could withstand DBE loads. If this is the case, a

failure of the nonsafety related portion of the pipe run or the associated piping anchors could

render the safety related portion of the piping unable to perform its intended function. The

SRP-LR states that in these cases the applicant's methodology would include (1) the remaining

nonsafety related piping up to its anchors and (2) the associated piping anchors as being within

the scope of license renewal under 10 CFR 54.4(a)(2).

Scoping implementation procedure LRP-PG-14, Section 5.1 states that for piping systems, the

nonsafety 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.

During the scoping methodology audit, the applicant stated that it defined the first equivalent

anchor as one'level of restraint in' each of the three orthogonal directions. The applicant stated

that this definition of equivalent anchor is consistent with its CLB. Specifically, Section 2.9.3,

"Seismic Design Criteria for Seismic Class I and 11 Piping," of the UFSAR, states that if a piping

system consists of a combination of seismic Class I, Class II, and/or Class IlIl piping, the piping

model may be structurally decoupled at an anchor or a point (or points) encompassing

restraints in the three orthogonal directions.

RAI2.1-3

The staff concluded that the applicant's methodology to extend the scoping boundary of

nonsafety related piping attached to safety related systems to the first level of restraint in each

orthogonal direction is consistent with the applicant's CLB and the''SRP-LR. However, during

the methodology audit, the applicant stated that the location of the first equivalent anchor point

was not physically located in the as-built plant. Therefore, in RAI 2.1-3(a), the staff requested

additional information regarding the process the applicant 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. In particular, the staff requested that the

applicant describe the method it used to ensure that all material/environment combinations

between the safety/nonsafety interface and the first equivalent anchor during an AMR were

considered.

The applicant responded to RAI 2.1-3(a) by letter dated May 7, 2004. The applicant stated that

it showed the safety/nonsafety interface on the LRA drawings; howe'ver, the staff found that

these drawings do not show the exact location of the equivalent anchor. The applicant stated

that it included all material and environmental combinations in the LRA AMR summary tables to

assure that a review of systems within the scope of license renewal for 10 CFR 54.4(a)(1) or

10 CFR 54.4(a)(3), as well as 10 CFR 54.4(a)(2), was performed. The applicant 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) to identify piping classification changes. The

applicant reviewed piping classifications beyond the license'renewal boundaries indicated on

the drawings for these systems to ensure that no 'new material or environmental combinations

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existed. The applicant determined that this approach assured that the piping reviewed would

include the first equivalent anchor. If the applicant identified a piping material or environmental

change, the applicant compared it with the AMR results for that system or a connected system

to validate that the material and environmental combination was addressed. The applicant

concluded that this review confirmed that LRA Section 3.0, "Aging Management Review

Results," includes all applicable material and environmental combinations up to and including

the first equivalent anchor.

In reviewing the applicant's response to RAI 2.1-3(a), the staff could not determine if the

applicant used a consistent definition of an equivalent anchor throughout the scoping process.

Specifically, the applicant reviewed piping drawings up to an obvious anchor point (i.e., a larger

line or a larger component, such as a pump or heat exchanger), but it did not provide sufficient

information for the staff to verify that this anchor adequately bounded the equivalent anchor

point as defined by restraint in each of the three orthogonal directions. Furthermore, it was not

clear from the applicant's response that the scope of license renewal included larger

components providing piping support functions to nonsafety related piping attached to safety

related piping. In particular, if a major component performs an intended function by providing

an equivalent anchorage point for attached piping, the applicant should include the major

component within the scope of license renewal. Therefore, the staff asked the applicant to

provide additional clarification regarding the definition it used for the equivalent anchorage

point, the scoping method used for SSCs that constitute an equivalent anchorage point, and

clarification regarding the basis for its determination that the review approach described in the

RAI 2.1-3(a) response adequately bounded all SSCs within the scope of license renewal in

accordance with 10 CFR 54.4(a)(2).

On May 17, 2004 and May 21, 2004, the staff held conference calls with the applicant to

discuss the RAI and to provide further clarification of the staff's requested information. As a

result of those conference calls, the applicant provided a supplemental response to RAI 2.1-3 in

a letter dated August 11, 2004. The applicant's response stated that the definition for

equivalent anchor is a point or points encompassing restraints in three orthogonal directions.

This definition is consistent with the CLB and is described in Section 2.9.3 of the applicant's

UFSAR. In addition, the applicant clarified that there were cases in which nonsafety related

piping attached directly to safety related piping terminated at a major component (i.e., plant

equipment that is anchored to a structure such that all 6 degrees of freedom of a piping system

are restrained). For those cases, that major component was considered within scope because it

provided the nonsafety related piping anchorage, and was subject to an aging management

program (i.e., LRA Section B.1.32, Structures Monitoring Program).

The staff concluded that the applicant provided an adequate basis for its determination of the

equivalent anchor location consistent with the plant CLB, and the identification of plant

equipment providing nonsafety related piping anchorage. On the above basis, RAI 2.1-3(a) is

resolved.

Leakage, Spray, or Flooding

The applicant considered spatial interactions between safety related and nonsafety related

equipment that are either not directly attached to a safety related system or do not provide a

supporting function for a safety related intended function during the second stage of

10 CFR 54.4(a)(2) scoping. The applicant considered certain spatial interactions to be credible,

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including leakage or spray, physical impact from falling or missile generation, and HELBs. To

address the effects of leakage, spray, and flooding,-the applicant used a bounding spaces

approach to identify nonsafety related equipment that could spatially interact with safety related

SSCs. The 10 CFR 54.4(a)(2) scoping process described in LRP-PG-14, Section 7.0,

"Scoping/screening Method to Address 10 CFR 54.4(a)(2)," and LRP-MAMR-35, Section 2.2.4,

"Leakage, Spray, Flooding," includes the following steps:

* The applicant identified the safety-related structures using the civil/structural aging

management review reports (AMRRs). The safety related structures at the CNP site

include the containment building, auxiliary building, screen house and the portion of the

turbine building that contains the auxiliary feedwater pumps. During the methodologyaudit, the applicant confirmed that plant equipment performing a safety related intended

function is located within a safety related structure.

* Through the use of plant layout drawings and CNP FDB component location

information, the applicant identified systems in safety related structures containing liquid

or steam. The applicant considered only systems with nonsafety-related components in

the safety-related structures for inclusion within scope for 10 CFR 54.4(a)(2). The

applicant eliminated systems containing safety-related components with an AMRR

prepared that have no nonsafety-related components, the failure of which could impact

safety-related SSCs from further review, since they are already within scope for

10 CFR 54.4(a)(1)(i-iii).

* The applicant eliminated nonsafety-related systems and nonsafety-related portions of

safety-related systems if justification was provided that their failure cannot adversely

impact the performance of safety functions. This justification may rely on system

walkdowns or drawing and database reviews.

* The applicant placed systems determined to have components, the failure of which

could adversely impact the performance of safety functions,- within the scope of license

renewal in accordance with 10 CFR 54.4(a)(2). Only the components in those systems

with the potential for spatial interaction with safety-related equipment are subject to an

AMR.

* The applicant then performed an AMR of the component commodity types in

nonsafety-related systems or nonsafety-related portions of systems with the potential for

- adverse spatial interaction with safety-related SSCs. Using the gerieric AMR, the

applicant identified AMPs for managing the aging effects of the material and'

environment combinations.-

* The applicant documented the results of the scoping for 10 CFR 54.4(a)(2) in the

license renewal information system database. Additionally, LRP-MAMR-3 documents

the results of the spatial interaction review for 10 CFR 54.4(a)(2) scoping. - -

Although the applicant's spaces approach for.10 CFR 54.4(a)(2) scoping appears to provide

bounding results, the staff determined that this methodology includes several assumptions that

could potentially limit the range of spatial interactions between nonsafety related and safety

related equipment considered by the applicant. Specifically, Section 5.2.3, "Leakage, Spray, or

Flooding," of LRP-PG-14 and Section 2.1.1.2.2 of the LRA state that long-term exposure to --

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conditions resulting from a failed nonsafety related SSC (such as leakage or spray) is not

considered credible. This conclusion is based on the applicant's assumption that leakage and

spray from liquid-filled low-energy systems would be detected during routine operator rounds or

system walkdowns before it could impact the performance of safety-related equipment.

Furthermore, the staff determined that the applicant's spaces approach for scoping nonsafety

related equipment in accordance with 10 CFR 54.4(a)(2) appears to be based, in part, upon the

assumption that both active and passive safety related equipment can withstand short-term

wetting without loss of intended function. Because the LRA clearly describes the basis for

these assumptions, the staff requested, in RAI 2.1-3(b), that the applicant clarify its position and

methodology relative to the consideration of spray and wetting of safety related SSCs resulting

from the failure of nonsafety related equipment. Specifically, the staff requested the applicant

to address the following:

* The staff requested clarification of the applicant's basis for its determination that longterm exposure to conditions resulting from a failed nonsafety related SSC is not

considered credible. Specifically, the staff requested the applicant to address if it

excluded nonsafety-related SSCs from the scope of license renewal based on the

applicant's determination that long-term exposure of safety related SSCs to conditions

resulting from failed nonsafety related equipment (i.e., wetting or spray) is not

considered credible.

* The staff requested a description of how the applicant considered the effects of shortterm wetting and spray on passive and active safety related SSCs during

10 CFR 54.4(a)(2) scoping. Furthermore, if it assumed that safety related SSCs could

withstand short-term spray or wetting without loss of intended function, the staff

requested the applicant to describe the basis for this assumption.

* The staff asked the applicant if it used the System Walkdown Program described in

Section B.1.38, "System Walkdown," of the LRA as the sole AMP for any nonsafety

related structures or components that could potentially spatially interact with safety

related SSCs. If the System Walkdown Program alone manages the effects of aging for

any nonsafety related SSC, the staff requested the applicant to describe how it

considered the effects of short-term spray and wetting during scoping and AMR

evaluations.

The applicant responded to RAI 2.1-3(b) by letter dated May 7, 2004. Although the applicant

acknowledged that LRA Section 2.1.1.2.2 states that long-term exposure to conditions resulting

from a failed nonsafety related SSC (such as leakage or spray) is not considered credible, it did

not apply this conclusion during its scoping evaluations. If a steam or liquid-filled nonsafety

related system (or nonsafety related portion of a safety related system) is in a safety related

building, then the applicant considered that system to be within the scope of 10 CFR 54.4(a)(2),

regardless of potential exposure duration. The applicant did not exclude nonsafety related

SSCs from the scope of license renewal based on the consideration that long-term exposure to

conditions resulting from a failed nonsafety related SSC is not credible. Additionally, the

applicant stated that it considered the potential for wetting or spray on passive and active safety

related components in its scoping evaluations. The applicant also considered nonsafety related

systems containing steam or liquid that are near safety related equipment as within the scope

of 10 CFR 54.4(a)(2), regardless of potential exposure duration. Further, the applicant stated

that it did not apply an assumption that safety related SSCs could withstand short-term spray or

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wetting without loss of intended function during scoping or screening. However, the applicant

determined that the System Walkdown Program, as described in Section B.1.38 of Appendix B

to the LRA, is adequate since it requires periodic walkdowns that would detect and correct

failures caused by long-term exposure to spray or wetting. Active safety related component

failures resulting from short-term exposure would be detected in the course of normal operation

or through monitoring required by the Maintenance Rule, and the applicant would take

appropriate corrective actions.

In reviewing the applicant's RAI response, the staff determined that the applicant's bounding

scoping approach includes an adequate range of nonsafety related SSCs that perform a

10 CFR 54.4(a)(2) intended function. In particular, the applicant clarified that it considered thepotential for wetting or spray on passive and active safety related components in scoping

evaluations, did not use potential exposure duration to exclude SSCs from the scope, and, if a

steam or liquid-filled nonsafety related system (or nonsafety related portion of a safety related

system) was in a safety related building, that system was considered within the scope of

10 CFR 54.4(a)(2). The staff concluded that this approach is consistent with the

10 CFR 54.4(a)(2) scoping guidance contained in the SRP-LR and the staff's December 3,

2001, and March 15, 2002, interim guidance letters. However, the staff notes that the sole use

of a system walkdown AMP for aging management of a nonsafety related SSC that could

spatially interact with safety related SSCs might, in certain circumstances, result in the loss of a

safety related intended function. In particular, the applicant's RAI response indicates that the

Corrective Action Program and Maintenance Rule Program would be used to correct safety

related SSC failures caused by short-term spatial interactions. The staff questioned whether

reliance on the Corrective Action Program to correct a safety related intended function failure

because of an age-related nonsafety related SSC failure constitutes adequate implementation

of either a mitigative or preventive approach to 10 CFR 54.4(a)(2) scoping, as described in the

staff's March 15, 2002 letter. In particular, the staff lacked sufficient information to conclude

that the applicant would consider and manage the effects of aging on nonsafety related SSCs

in a manner that would provide reasonable assurance that the safety related SSCs will be able

to perform their intended functions. Despite this concern, the staff determined that the

applicant, through the use of the spaces approach to scoping, identified the nonsafety SSCs of

concern within the scope of license renewal. Consequently, this issue is more closely

associated with the review of AMP adequacy than with the scoping methodology. Therefore,

Open Item 3.3.2.1.11-1, discussed in Section 3.3.2.3.11 of this report, addresses the concerns

associated with the potential for loss of safety related intended functions because of agerelated failure of nonsafety related SSCs. Because the staff concluded that the applicant's

spaces approach to 10 CFR 54.4(a)(2) scoping adequately identified nonsafety related SSCs

with the potential to spatially interact with safety related SSCs, RAI 2.1-3(b) is resolved.

The applicant generically excluded certain nonsafety related gas-filled systems from the scope

of license renewal based on the determination that there is no credible mechanism for these

systems to adversely impact safety related SSCs. The applicant based this determination on a

review of CLB information and operating experience. Section 2.1, "Operating Experience

Review," of LRP-MAMR-35 states that the applicant reviewed Corrective Action Program

databases dating from October 1997 to October 2002. The applicant used keyword searches

to identify corrective action documents related to leak, spray, seep and rupture. The applicant

stated that it reviewed each condition report description if it appeared to contain information

relative to the intent of the search. Based on this review, the applicant found no instances of

failures in air/gas systems that either caused the failure of other plant equipment or had the

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potential of adversely affecting safety-related plant equipment. The applicant stated that it also

reviewed generic NRC industry operating experience and found no items describing instances

in which nonsafety related air/gas system leakage or ruptures adversely impacted

safety-related equipment.

During the scoping and screening methodology audit, the applicant indicated that it based the

5-year timeframe for operating experience review, in part, on the electronic search capabilities

of the Corrective Action Program database. Although the applicant stated that it reviewed sitespecific CRs only for a minimum of 5 years, the staff noted that this timeframe bounded the

performance of the ESRR program reviews. As described in Section 2.1.1 of the LRA, the

ESRRs assess the conformance of the plant design, testing, maintenance, operation, and

configuration with the licensing and design-basis requirements. During the ESRR program, the

applicant entered identified technical issues into the Corrective Action Program database. The

NRC staff previously inspected the implementation of the ESRR and concluded that, overall,

the applicant effectively implemented the program (see NRC Inspection Report Nos. 50-315

and 50-316/1999-02, /1999-03, and /1999-07). Additionally, in reviewing the results of the

condition report reviews conducted by the applicant, the staff noted that, in many instances,

CRs dating beyond the minimum 5-year timeframe were identified. The staff also conducted an

independent review of LERs from CNP and verified that information contained in previous CNP

LERs did not invalidate the applicant's conclusions with regard to site-specific failures of gas

systems. On this basis, the staff concluded that the applicant adequately considered sitespecific and industry operating experience in its determination that there have been no failures

of air/gas systems that adversely affected the safety-related SSCs. Therefore, the staff

concluded that it was appropriate for the applicant to exclude nonsafety related gas-filled

systems form the scope of license renewal.

Physical Impact

The applicant considered physical impact between nonsafety related equipment and safety

related SSCs as a credible means for adverse spatial interactions. This category concerns the

potential spatial interaction of nonsafety-related SSCs falling on, or otherwise physically

impacting, safety related SSCs such that their safety functions may not be accomplished. As

described in LRP-PG-14, Section 5.2.1, "Physical Impact," the applicant included all nonsafety

related supports for nonseismic or seismic 11/I piping systems with a potential for spatial

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

10 CFR 54.4(a)(2). In addition, LRP-MAMR-35, Section 2.2.1, "Physical Impact," also notes

that electrical conduit and cable trays with a potential for spatial interaction with safety related

SCs are also considered within the scope of license renewal, in accordance with

10 CFR 54.4(a)(2). However, the applicant stated that, based on earthquake experience data,

no experience exists of welded steel pipe segments falling from a strong motion earthquake

and that falling of piping segments is extremely rare and only occurs when there is a failure of

the supports. Therefore, the applicant concluded that, as long as the effects of aging on the

supports for these piping systems are managed, it did not consider falling of piping sections

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

of the physical impact hazard. However, the applicant noted in LRP-PG-14 that the effects of

spray and leakage must be considered before concluding that the associated piping section

could be eliminated from scope. Because the applicant considered other types of spatial

interactions in addition to falling, such as leakage and spray, before determining that nonsafety

related piping could be eliminated from the scope under 10 CFR 54.4(a)(2), the staff

2-24
determined that this approach is consistent with the SRP-LR and staff expectations contained in

the staff's December 3, 2001 and March 15, 2002 letters.

The applicant also considered physical impact caused by a load drop from an overhead

handling system or missiles. The applicant considered overhead-handling systems from which

a load drop could prevent the accomplishment of a safety related intended function to be within

the scope of license renewal and subject to an AMR. Additionally, the applicant considered

inherent nonsafety related features that protect safety-related equipment from missiles from

either internal or external events to be within the scope of license renewal in accordance with

10 CFR 54.4(a)(2) and subject to an AMR. The staff determined that the applicant considered

an adequate range of falling and physical impact spatial interactions during its

10 CFR 54.4(a)(2) scoping evaluations.

Pipe Whip, Jet Impingement, or Harsh Environments

As described in LRP-PG-14, Section 5.2.2, "Pipe Whip, Jet Impingement, or Harsh

Environments," the applicant considered that the spatial interactions of pipe whip, jet

impingement, and harsh environments are credible only for high-energy systems. In

LRP-PG-14, Section 5.2.2, the applicant states that a high-energy system operating at a

temperature and pressure of greater than 93 0C (200 'F) and 275 psi, containing piping with a

diameter of 1 inch or less, is excluded from consideration. The staff determined that this

definition of high-energy piping and identification of credible spatial interactions is consistent

with UFSAR Sections 14.4.2.1, "High Energy Systems Definition," and 14.4.2.6, 'Pipe Rupture

Locations and Evaluation." LRP-PG-14, Section 5.2.2 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 must be within the scope of license renewal in accordance with

10 CFR 54.4(a)(2) and subject to an AMR to provide reasonable assurance that those

assumptions remain valid through the period of extended operation. Additionally, LRP-PG-14

states that if required safety-related equipment is not protected from the effects of a HELB,

then the high-energy piping is within the scope of license renewal and subject to AMR.

The March 15, 2002 letter regarding 10 CFR 54.4(a)(2) scoping describes the staff position for

scoping of high-energy piping systems. This letter notes that an applicant may use mitigative

and/or preventive approaches to scoping nonsafety related high-energy piping systems. If a

mitigative approach is used, the applicant should demonstrate that the plant's mitigative

features are adequate to protect safety related SSCs from nonsafety related SSC failures,

regardless of failure location. If an applicant cannot demonstrate that the mitigative featuresare adequate to protect safety related SSCs from the consequences of nonsafety related SSC

failures, then the entire nonsafety related SSC must be-brought into the scope of license:

renewal. The staff determined that the applicant's approach to scoping high-energy systems is

consistent with the staff position stated in the March 15, 2002 letter. Specifically, the staff

concluded that the applicant applied a preventive approach and appropriately scoped highenergy piping, the failure of which could prevent the satisfactory accomplishment of a safety

related intended function, in a manner consistent with the CLB.

Conclusion. To provide additional assurance that the applicant adequately implemented their

nonsafety related scoping methodology, the NRC methodology staff reviewed a sample of the

license renewal scoping results for ice condenser, auxiliary feedwater, emergency core cooling,

and main feedwater systems. The staff concluded that the applicant adequately implemented

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L

the 10 CFR 54.4(a)(2) scoping process. Additionally, the staff determined that the applicant identified and used pertinent engineering and licensing information to support the scoping determinations for the items sampled.

On the above basis, the applicant's methodology for scoping nonsafety related equipment under 10 CFR 54.4(a)(2) adequately identified those nonsafety related SSCs whose failures are considered in the CLB and could prevent the satisfactory accomplishment of the safety related functions identified under 10 CFR 54.4(a)(1). Therefore, the staff determined that the applicant's methodology for identifying systems and structures meeting the scoping criteria of

10 CFR 54.4(a)(2) was adequate.

Application of the Scoping Criteria in 10 CFR 54.4(a)(3). As required by 10 CFR 54.4(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 NRC's regulations for FP (10 CFR 50.48), EQ (10 CFR 50.49), PTS (10 CFR 50.61), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63) to be within the scope of the license renewal. Section 2.1.3.1.3, "Regulated Events," of the SRP-LR states that all SSCs that are relied upon in the plant's CLB (as defined in 10 CFR 54.3), plant- specific operating experience, industrywide operating experience (as appropriate), and safety analyses or plant evaluations to perform a function that demonstrates compliance with NRC regulations under 10 CFR 54.4(a)(3) must be included within the scope of the Rule. However, consideration of hypothetical failures that could result from system interdependencies that are not part of the CLB, and that have not been previously experienced, is not required.

The staff reviewed the applicant's approach to identifying SSCs relied upon to perform a function related to the five regulated events described in 10 CFR 54.4(a)(3). As part of this review, the staff discussed the methodology with the applicant's LRA team, evaluated the documentation developed to support the review, and evaluated a sample of the resultant SSCs identified as within scope for the 10 CFR 54.4(a)(3) criterion.

The applicant documented the methodology for performing the scoping of SSCs in accordance with 10 CFR 54.4(a)(3) in implementation procedures LRP-PG-01, Revision 5, "Scoping Systems and Structures," and LRP-PG-06, Revision 1, "License Renewal Topical Reports." A series of individual topical reports for ATWS, PTS, SBO, FP, and EQ (Topical Report for License Renewal Scoping LRP-TR-01 through LRP-TR-05, respectively) documents the results

of the applicant's review for each regulated event.

The applicant developed the set of topical reports LRP-TR-01 through LRP-TR-05 to collect the CLB information pertaining to each regulated event and to identify specific SSCs relied upon in the CLB to perform an intended function for those specific regulated events. To help ensure development of a consistent and comprehensive set of reports, the applicant initially developed implementation guideline LRP-PG-06, which contains format and content requirements for topical report generation. Project guideline LRP-PG-06 contains detailed information on the initiation of a topical report, preparation steps, review and approval procedures, and process for topical report revision. In addition, the guideline provides useful tables of potential CLB source documentation, as well as final report format requirements. The staff found the LRP-PG-06 guideline to be detailed and useful for review of the topical reports.

The staff also reviewed the set of topical reports for each regulated event. Each report contains a detailed description of the history of the specific regulated event, a chronology of the plant2-26
specific design and licensing basis related to the regulation, and a description of the various

systems and structures and their specific intended functions associated with and credited for

the pertinent regulated event. The reports also identify the CLB source information, which is

retained in a retrievable format to allow for reviewing specific results associated with individual

systems and structures. The applicant identified these sources primarily through the use of the

plant's electronic documentation program, "Folio," which contains the regulations, plant-specific

design calculations, UFSAR, licensing correspondence, design change information, generic

communications, and industry operating experience reports. The applicant's license renewal

project team developed the reports, which were reviewed by a subject matter expert, LRA

management, and independent contractors.

The staff also reviewed the applicant's specific actions to address the ISG pertaining to SBO.

In a letter from D. Matthews (NRC) to A. Nelson and D. Lochbaum dated April 1, 2002, the staff

provides additional guidance for scoping of equipment relied on to meet the requirements of the

SBO rule. This staff guidance, identified as ISG-2, "Scoping of Equipment Relied Upon to Meet

the Requirements of the Station Blackout (SBO) Rule for License Renewal," states that the staff

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 license renewal. This

path typically includes the switchyard circuit breakers that connect to the offsite system power

transformers (startup transformers), the transformers themselves, the intervening overhead or

underground circuits between circuit breaker and transformer and transformer and onsite

electrical distribution system, and the associated control circuits and structures. In Section

2.1.3 of the LRA, the applicant stated that scoping is in accordance with ISG-2. Additionally,

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

Systems," of the LRA, states that the offsite power system is included in the scope of license

renewal. The LRA further states that the offsite power system provides the electrical

interconnections between the offsite network and the station auxiliary buses, as well as

electrical interconnections among other buildings and facilities located on the CNP site. Based

on the applicant's consideration of the offsite power system during SBO scoping evaluations,

the staff determined that the applicant's scoping methodology adequately addresses ISG-2.

Section 2.5 of this SER further discusses the staff's assessment of the actual electrical power

scoping results.

Conclusion

As part of the review of the applicant's scoping methodology, the staff reviewed a sample of the

license renewal database's 10 CFR 54.4(a)(3) scoping results to assess the adequacy of the

applicant's scoping methodology. The staff verified that the applicant's scoping methodology

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 and verified that

the applicant's LRA staff was cognizant of the requirements for evaluating and documenting the

review. On the basis of its review, the staff concludes that the applicant adequately defined and

implemented a methodology for identifying systems and structures to meet the scoping criteria

of 10 CFR 54.4(a)(3).

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- lI

2.1.3.1.3 Plant Level Scoping of Systems and Structures

Section 5.4 of LRP-PG-01 describes the applicant's methodology for performing the scoping of

systems and structures. The applicant identified each system or structure within the scope of

license renewal as follows:

* The applicant selected a system or structure from a list of plant systems based on

system codes contained in the FDB. Procedure 12-EHP-5043-FDB-001, Section 4.7,

"Approved Plant System Codes," identifies the FDB as the primary repository for

approved plant system codes to be used at the CNP.

* The applicant obtained the information on the selected system or structure from a

review of CLB and related documents.

* Based on the CLB information, the applicant identified mechanical system or structural

level functions. The applicant documented the license renewal intended functions by

completing a system function scoping table for each mechanical system or structure

function. The staff determined that the nine scoping questions included on the system

function scoping table were consistent with each of the scoping criteria of

10 CFR 54.4(a).

* Project guideline LRP-PG-01, Section 5.5, "System Boundary Details," states that

boundaries are determined by mapping the pressure boundary associated with the

license renewal intended functions onto the system flow diagrams. All the equipment

and piping shown on the drawings is initially assumed to be part of the system. Flow

diagrams, one-line drawings, civil/structural drawings, and text description provide

system boundaries, as appropriate.

* To facilitate the scoping and screening process and the AMRs, the applicant realigned

certain components from its FDB parent system to another system. Project guideline

LRP-PR-01, Section 2.0, "Methodology," states that system boundaries are established

in terms of the major intended functions they perform. This permitted the AMRs of

some UFSAR-described systems or portions of systems to be combined with other

system reviews, which allows clearer alignment to the systems described in NUREG1801, "Generic Aging Lessons Learned (GALL) Report," issued July 2001. The

applicant stated that individual system/structure scoping reports (ISSRs) describe the

boundaries of the system with references to applicable boundary drawings, including the

effects of any system combinations established for the review. Component realignment

is intended to allow components to be evaluated as a coherent functional group within

an appropriate system or commodity group. The implementation procedure includes

documentation requirements to permit traceability of components that realign from one

parent system to a different license renewal system.

* The associated ISSR documents the results of system and component level scoping.

The ISSR includes a system description, a system boundary evaluation, information

about interfacing systems, identification of system or structure functions, the completed

system function scoping question table, and associated references. The applicant

established guidance for the preparation of ISSRs in LRP-PG-01, Section 5.7, "Review

and Approval of ISSRs," which provides guidance for the review and approval of ISSRs.

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All ISSRs require engineering manager approval. Additionally, senior reactor operator

and system manager reviews are required for certain systems or structure ISSRs. The

applicant summarized the system and structure scoping process and the results of the

identification of systems and structures that are within the scope of license renewal in

LRP-PR-01, "Final System and Structure Scoping Report."

During the scoping methodology audit, the staff reviewed a sampling of ISSRs and concluded

that the applicant's scoping reports contained an appropriate level of detail to document the

scoping process. In particular, the ISSRs and the final system and structure scoping report

contain sufficient detail to permit the identification of system and structure intended functions

and scoping evaluation boundaries. Additionally, during the scoping and screening

methodology audit, the staff reviewed the implementation of the component realignment

guidance and determined that the realignment process did not adversely impact componentlevel scoping and screening.

Conclusion

Based on a review of the LRA, the scoping and screening implementation procedures, and a

sampling review of system and structure scoping results during the methodology audit, the staff

concluded that the applicant's scoping methodology for systems and structures is adequate.

Specifically, the staff determined that the applicant's methodology reasonably identifies systems

and structures within the scope of license renewal and their associated intended functions.

2.1.3.1.4 Component Level Scoping

The applicant considered scoping to be the process of identifying systems and structures that

perform a license renewal intended function. The licensee did not describe a component level

scoping process in the LRA, but instead indicated that it performed component-level scoping as

an integral part of the screening process. However, as described in Section 5.5 of LRP-PG-01,

the components within a system are scoped during the screening phase (not the scoping

phase). Framatome/Entergy, the applicant's primary contractor for license renewal, performed

the component level scoping and screening phase. Using the ISSRs prepared by the applicant

and CLB information sources, Framatome/Entergy performed component level scoping and

screening evaluations. Framatome/Entergy used approved license renewal project procedures

to perform detailed component level evaluations. The AMRRs and marked system flow

diagrams document the results of the component level scoping and screening evaluations. The

applicant's administrative controls for the license renewal project include procedures for the

owner acceptance review of license renewal documents prepared by contractor personnel.

Therefore, although Framatome/Entergy prepared the AMRRs, the applicant's license renewal

project team members and engineering manager are responsible for their review and approval.

The scope of the owner acceptance review includes verification that all system level intended

functions are included, the correlation between scoping drawings and intended functions, and a

review of scoping results-for major components.

Although the applicant considered component level scoping as part of the screening process,

the staff evaluated the methodology the applicant used to identify components necessary to

support system and structural level intended functions. After the applicant identified systems

and structures within the scope of licensee renewal and their associated intended functions, the

applicant performed a review to identify the components of each in-scope system and structure

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that supports an intended function. As described in Section 2.1.1 of the LRA, a component is

determined to be in-scope if it is safety related, pursuant to 10 CFR 54.4(a)(1), is needed to

fulfill a system intended function, pursuant to 10 CFR 54.4(a)(2), or is needed to demonstrate

compliance with a regulated event. The following sections describe the staff review of the

methodology to scope mechanical, structural, and electrical components.

Mechanical Component Scoping. Project guideline LRP-PG-04 provides the applicant's

proceduralized guidance for scoping mechanical system components. Section 5.1, "Screening

of Components," of LRP-PG-04, states that, for each mechanical system within the scope of

license renewal, the screening process will identify those components that are subject to an

AMR. Component level scoping and screening evaluations consist of the following major

activities:

* The applicant identified the system evaluation boundary by indicating those portions of

the system that are necessary to ensure that the intended functions of the system will be

performed. It used the information contained in the ISSRs as the primary basis for

determining the evaluation boundary. Project guideline LRP-PG-04 requires that this

identification of evaluation boundaries be based on the CLB, plant-specific experience,

industrywide operating experience as appropriate, and existing design-basis

documentation.

* The applicant also identified components subject to an AMR. Within the evaluation

boundary, 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 accordance with the scoping and screening methodology, the applicant performed

component level scoping and screening during this portion of the methodology. In LRPPR-04, Section 5.1.2 states that long-lived, passive components within the evaluation

boundary are subject to an AMR.

* Finally, the applicant documented component intended functions. Procedure LRP-PG04, Section 5.1.2, states that passive, long-lived components within the evaluation

boundary should be documented in the associated AMRR. Additionally, the AMRR

includes a summary statement of the component level intended functions. The

component intended function is the specific simple function, such as "maintain pressure

boundary," that supports the broader system intended function.

RAI 2.1-5

In general, the staff concluded that the applicant's methodology adequately scopes mechanical

components that support a system level intended function. However, during the audit, the

applicant could not adequately describe the evaluation that it performed to determine if any

insulation installed in the plant is required to support any system intended functions identified

during the scoping process. As a result, the staff requested in RAI 2.1-5 that the applicant

describe any intended functions performed by insulation or the basis for determining that

insulation (i.e., piping insulation) does not meet the scoping criteria described in

10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), or 10 CFR 54.4(a)(3).

The applicant responded to RAI 2.1-5 by letter dated May 7, 2004. The applicant stated that, in

some internal plant locations, piping insulation serves the intended function of limiting heat loss

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to reduce area heat loads during an accident. The applicant noted that insulation that performs

an intended function at the CNP site is located indoors and protected from the weather. The

applicant also indicated that, based on site-specific operating experience, indoor insulation at

CNP has no aging effects requiring management (AERMs).

In reviewing the applicant's response, the staff concluded that piping insulation performs an

intended function at the CNP site. However, the applicant did not identify piping insulation as

either a component or commodity type within the scope of license renewal. Because insulation

performs its intended function without moving parts or without a change in configuration or

properties and is generally not subject to periodic replacement, insulation within the scope of

license renewal should be subject to an AMR in accordance with the requirements of

10 CFR 54.21. Although the applicant noted that it reviewed plant-specific operating

experience to identify aging-related degradation mechanisms for insulation, the staff concluded

that this information pertained more to the AMR than to the scoping evaluation. Furthermore, in

accordance with staff guidance issued for 10 CFR 54.4(a)(2) scoping evaluations, exclusion of

SSCs from the scope based on a review of site-specific and industry operating experience

applies only to the identification of noncredible failures of nonsafety related scoping pursuant to

10 CFR 54.4(a)(2). Additionally, the staff could not determine whether the applicant had

considered industry operating experience or potential insulation intended functions in

accordance with the 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) scoping criteria. Therefore, the

staff lacked sufficient information to conclude that the applicant's scoping methodology

adequately considered the intended functions performed by piping and component insulation.

On May 17, 2004, and May 21, 2004, the staff held conference calls with the applicant to

discuss the RAI and to further clarify the staff's requested information. As a result of those

conference calls, the applicant provided a supplemental response to RAI 2.1-5 in a letter dated

August 11, 2004. The applicant's response stated that in some internal plant locations,

including portions of piping in the engineered safety features (ESF) systems (emergency core

cooling, and auxiliary feedwater), piping insulation performed an intended function, and is

therefore in scope for license renewal. The applicant performed an AMR of the system piping

effected.

On the basis of the information provided by the applicant, which included (1) a discussion of the

relevant systems with insulation that perform an intended function, (2) inclusion of that

insulation within scope of license renewal, and (3) performance of an AMR of the insulation, the

staff concludes that the applicant provided an adequate basis for the evaluation and

determination of insulation within the scope-of license renewal. On the above basis, RAI 2.1-5

is resolved.

Conclusion. The staff reviewed a sampling of scoping results for the ice condenser, auxiliary

feedwater, emergency core cooling, and main feedwater systems during the scoping and

screening methodology audit to verify that the applicant's proceduralized methodology was

adequately implemented. For the samples reviewed, the staff determined that the applicant

effectively implemented the scoping methodology. Additionally, the applicant adequately

documented and justified the results of the component level scoping process.

The staff determined that the applicant's proceduralized methodology is consistent with the

description provided in LRA and the guidance contained in the SRP-LR, Section 2.1, and was

adequately implemented. Based on a review of the applicant's detailed scoping implementation

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procedures, and a sampling review of mechanical components scoping results, the staff

concluded that the applicant's methodology for identifying mechanical components within the

scope of license renewal meets the requirements of 10 CFR 54.4(a).

Structural Component Scopina. Implementation procedure LRP-PG-03 provides guidance for

the scoping and screening of structural components. Procedure LRP-PG-03 includes the

following steps for structural component scoping:

Identification of structural components-For each structure within the scope of license

renewal, the applicant evaluated the structure's structural components and commodities

to determine those subject to an AMR. As part of the screening process for structural

components and commodities, the applicant reviewed DBDs (i.e., UFSAR, drawings,

and specifications) to identify specific structural components and commodities that make

up the structure. The applicant noted that structural components and commodities often

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

the applicant grouped structural components and commodities based on materials of

construction as a means of categorizing them for AMRs.

* Identification of structural component and commodity groups-The applicant

categorized structural components and commodities by the materials of construction.

LRP-PG-03 stated that a review of DBDs (i.e., UFSAR, drawings, and specifications) is

required to determine specific material types for structural components and

commodities.

* Identification and documentation of structural component intended function-The

applicant also evaluated structural components and commodities to determine intended

functions as they relate to the license renewal process. Procedure LRP-PG-03 refers to

the intended function guidance in NEI 95-10 and provides a listing of structural intended

functions to be used during scoping. LRP-PG-03 also states that the applicant should

document structural components and commodities applicable to a particular structure, in

addition to the associated intended functions, in the AMRR.

The staff concluded that the applicant's methodology for scoping structural components

provides reasonable assurance that structural components would be appropriately scoped in

accordance with 10 CFR 54.4(a). The staff reviewed the applicant's list of structural intended

functions provided in LRP-PG-03 and determined that the applicant considered all the structural

intended functions in SRP-LR, Table 2.1-4, "Typical Passive Structure and Component

Intended Functions."

Conclusion. The staff determined that the applicant's proceduralized methodology is consistent

with the description provided in Section 2.1.2.2 of the LRA and the guidance contained in the

SRP-LR, Section 2.1. Based on review of information contained in the LRA, the applicant's

detailed scoping implementation procedures, and a sampling review of structural component

scoping results, the staff concludes that the applicant's methodology for the identification of

structural components within the scope of license renewal meets the requirements of

10 CFR 54.4(a).

Electrical and l&C Component Scoping. Section 2.5.3.1, "Components Within the Scope of

License Renewal, of the SRP-LR, states that an applicant may use the plant spaces approach

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in scoping electrical and l&C components. In the plant spaces approach, an applicant may

indicate that all electrical and l&C components located within a particular area are either within

or not within the scope of license renewal. SRP-LR, Table 2.5-1, "Examples of 'Plant Spaces'

Approach for Electrical and l&C Scoping and Corresponding Review Procedures," provides

guidance for-the review of scoping performed in accordance with the plant spaces approach. In

particular, if the applicant limits the scope of electrical and l&C components considered within

the scope of license renewal by excluding components in certain plant spaces, SRP-LR, Table

2.5-1, indicates that this approach should not result in failing to place electrical and l&C

components that perform intended functions within the scope of license renewal.

Implementation procedure LRP-PG-05, "Electrical System Scoping, Screening and Aging

Management Reviews," and topical report LRP-TR-06, "Methodology for Assigning Electrical

Component Commodity Groups," provide guidance for the scoping and screening of electrical

components. Procedure LRP-PG-05 discusses the activities associated with the electrical

component scoping, as well as screening information and aging management report

information. Topical report LRP-TR-06, provides detailed information on electrical component

and commodity type designations and is based primarily on industry guidance embodied in NEI

95-10 and the Electric Power Research Institute (EPRI) License Renewal Electrical Handbook.

For the license renewal evaluation, initial plant-specific electrical component types are identified

from several information sources, including the plant equipment database, electrical system and

raceway drawing and information, and field evaluations. The applicant used the results of this

initial review to develop a comprehensive list of plant-specific electrical commodity groups,

consistent with the guidance in Appendix B to NEI-95-10, which encompasses all of the types of

electrical components identified through the application of the spaces approach. The applicant

further evaluated the resultant commodity groups to identify those that are passive, in

accordance with the 10 CFR Part 54.21 (a)(1)(i) criterion. As a result, two commodity groups,

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

and (2) high-voltage insulators, were identified as passive. The applicant evaluated these two

commodity groups further and subdivided them into seven subcategories, consistent with the

guidance in Appendix B to NEI-95-10. Section 2.1.3.2.3 of this SER further discusses these

subcategories. The applicant documented the results of its evaluation in LRP-EAMR-01, "Aging

Management Review for Electrical Systems."

The staff reviewed the samples of the source information the applicant used to identify electrical

components and commodity groups, reviewed the process with cognizant members of the

applicant's LRA team, and reviewed a sample of the component and commodity types resulting

from the applicant's review effort. On the basis of these reviews, the staff concludes that the

applicant's implementation of the electrical spaces approach provides reasonable assurance

that electrical and I&C components that perform intended functions are within the scope of

license renewal.

Additionally, the staff reviewed the applicant's evaluation of fuse holders to assure that it

adequately considered the staff's guidance in ISG-5, "The Identification and Treatment of

Electrical Fuse Holders for License Renewal." Specifically, in a letter from D. Matthews (NRC)

to A. Nelson and D. Lochbaum, dated March 10, 2003 which transmits ISG-5, the staff provides

additional guidance for scoping of electrical fuse holders. In that ISG, the staff concludes that

fuse holders are passive, long-lived electrical components within the scope of license renewal

and subject to an AMR. However, the staff notes that fuse holders inside the enclosure of an

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active component, such as switchgear, power supplies, power invertors, battery chargers, and

circuit boards, are considered to be piece parts of the larger assembly and outside the scope

for license renewal. In LRA Section 2.1.3, the applicant stated that it will evaluate fuse holders

meeting the requirements of ISG-5 before the beginning of the period of extended operation for

possible AERMs. This is Commitment #32 in Appendix A of this SER. Furthermore, the

licensee stated in the LRA that it will either replace these fuse holders, modify them to remove

the aging effects, or implement a program to manage the aging effects. This approach is

consistent with LRA Table 2.1.1, "Standard List of Passive Electrical Commodities," which

includes fuse blocks in the list of passive electrical commodities subject to an AMR. The staff

concluded that, although the applicant has not identified specific fuse holders that are within

scope, the applicant included fuse holders in scope as an electrical commodity. Because the

applicant used a spaces approach for electrical scoping, the staff concludes that the inclusion

of fuse holders that are not part of a larger assembly as a commodity group meets the ISG-5

guidance for scoping of fuse holders.

Conclusion. The staff reviewed the samples of the source information used by the applicant to

identify electrical components and commodity groups, reviewed the process with cognizant

members of the applicants LRA team, and reviewed a sample of the component and commodity

types resulting from the applicant's review effort. On the basis of these reviews, the staff

determined that the implementation of the electrical spaces method for scoping of electrical and

l&C components is consistent with the guidance contained in the SRP-LR. Because the

applicant's use of the electrical spaces approach integrates the scoping and screening phases

of the methodology, Section 2.1.3.2.3 of this SER discusses additional conclusions regarding

the use of this method.

2.1.3.2 Screening Methodology

The staff reviewed the screening methodology used by the applicant to determine whether

mechanical, structural, and electrical components within the scope of license renewal would be

subject to further aging management evaluation. The applicant described its screening process

in Section 2.1.2 of the LRA. In general, the applicant's screening approach consists of

evaluations to determine which SCs that support an intended function are passive and longlived. Passive, long-lived SCs are then subject to further AMR.

The staff evaluated the applicant's screening methodology against the criteria contained in

10 CFR 54.21 (a)(1) and 10 CFR 54.21 (a)(2) using the review guidance in the SRP-LR,

Section 2.1.3.2, "Screening." 10 CFR 54.21(a)(1) states that the applicant's IPA must identify

and list those SCs subject to an AMR. Further, 10 CFR 54.21(a)(1) requires that SCs subject

to an AMR encompass those SCs that (1) perform an intended function, as described in

10 CFR 54.4, without moving parts or a change in configuration or properties, and (2) are not

subject to replacement based on a qualified life or specified time period. Pursuant to

10 CFR 54.21 (a)(2), the applicant must describe and justify the methods used to meet the

requirements of 10 CFR 54.21 (a)(1). In the LRA, the applicant described screening

methodologies that are unique to the mechanical, structural, and electrical disciplines. The

following describes the staff evaluation of the applicant's screening approach for each of these

disciplines.

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2.1.3.2.1 Mechanical Component Screening

The applicant provided procedural guidance for the conduct of mechanical component

screening in LRP-PG-04, Section 5.1.2, Identifying Components Subject to Aging Management

Review." This section states that, within the evaluation boundary, 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. The applicant defined the evaluation

boundary for mechanical systems to include those portions of a system that are necessary to

ensure that the intended functions of the system will be performed. Additionally, if the

component is not subject to replacement based on a qualified life or specified time period, then,

in accordance with procedure LRP-PG-04, the applicant considered the component long-lived.

The applicant did not include components that are 'not long-lived in the AMR. The applicant

noted that components subject to refurbishment or replacement solely on the basis of condition

monitoring (i.e., the component is replaced only if leakage is observed during a routine

walkdown) would be considered long-lived and require an AMR.-

The applicant grouped components into commodity groups, where possible, to allow disposition

of the entire group with a single AMR. The applicant stated that the grouping of components is

based on characteristics such as similar design, sim-ilar materials of construction, similar aging

management practices, and similar environments.

In a May 1, 2002 letter from P.T. Kuo (NRC) to A. Nelson and D. Lochbaum, the staff provided

guidance on the identification and treatment of housings for active components for license

renewal scoping and screening. As discussed in this letter, the staff expects applicants for

license renewal to identify active component housings (i.e., housings for fans, dampers, and

heating and cooling coils) which require an AMR. This determination should consider whether

failure of the housing would result in a failure of the associated active component to perform its

function, and whether the housing meets the long-lived and passive criteria defined in

10 CFR Part 54. In Section 2.1.3, "Interim Staff Guidance Discussion," of the LRA, the

applicant stated that the process used to identify passive components subject to an AMR -

identifies active component housings (i.e., pump casings, valve bodies, and housings for fans

and dampers) which are subject to AMR. In addition, the staff notes that LRA Table 2.3.3-6,

"Heating, Ventilation and Air Conditioning Systems Components Subject to Aging Management

Review," includes damper housings, fan housings, and filter housings as long-lived passive

components that provide a pressure boundary component level intended function. Based on

the above, the staff concludes that the applicant adequately addressed the interim guidance for

housings of active components described in the May 1, 2002 letter.

RAI 2.1-4

The applicant described the screening review for certain types of consumable commodities in

Section 2.1.2.4.1, "Packing; Gaskets, Component Seals, and O-Rings," of the LRA, which

states that packing, gaskets, component seals, and O-rings are not subject to condition or

performance monitoring which could demonstrate that specific criteria are met. During the

methodology audit and review of the applicant's screening methodology procedures, the staff

lacked sufficient information to determine'what specific methods and criteria the applicant used

to determine that these consumables are not subject to an AMR. SRP-LR, Table 2.1-3, --

"Specific Staff Guidance on Screening," provides guidance for determining if consumable items

should be subject to an AMR. For consumables that are periodically replaced, SRP-LR,

2-35.
- '_ 1'

Table 2.1-3, states that the applicant should identify the standards that it relied on for

replacement as part of the methodology description. For consumables such as packing,

gaskets, component seals, and O-rings, Table 2.1-3 states that these components may be

excluded from an AMR only upon demonstrating a clear basis. Therefore, in RAI 2.1-4, the

staff requested the applicant to clarify the basis used to exclude consumables from further

AMR.

In its May 7, 2004, response to RAI 2.1-4, the applicant stated that the two criteria discussed in

LRA Section 2.1.2.4.1 are (1) sealing materials that are short-lived because they are replaced

on a fixed frequency or have a qualified life, and (2) sealing materials not relied on to maintain

leakage below limits and not relied on to maintain system pressure high enough to deliver

required flows. The applicant stated that sealing materials that are considered short-lived

include: (1) electrical component sealing materials with a qualified EQ life; (2) reactor vessel

O-rings that are periodically replaced; and (3) reactor coolant pump (RCP) seals that are

periodically monitored and replaced as needed. The applicant noted that the RCP seals are a

highly visible and closely monitored element of the RCS. Further, the applicant has site-specific

procedures specifying performance monitoring and inspection activities of these seals and

subsequent seal replacement based on the results of these activities. In addition to these

commodities, the applicant also determined that pressurizer manway gaskets do not require an

AMR because they are not required to maintain pressure boundary integrity. The applicant

concluded that packing, gaskets, component seals, and O-rings that are not considered

pressure boundaries per American Society of Mechanical Engineers (ASME) Boiler and

Pressure Vessel Code, Section III, do not require an AMR. Because the staff determined that

the applicant provided a clear basis for its treatment of packing, gasket, component seals and

O-rings, RAI 2.1-4 is resolved.

The staff determined that the applicant's screening criteria are consistent with the requirements

of 10 CFR 54.21 and are therefore acceptable. In particular, the screening process provides

reasonable assurance that passive, long-lived mechanical components within the scope of

license renewal would be subject to an AMR.

Conclusion

Based on the above, the staff determined that the applicant's mechanical screening

methodology is consistent with the guidance contained in the SRP-LR and is capable of

identifying passive, long-lived components within the scope of license renewal that are subject

to an AMR.

2.1.3.2.2 Structural Component Screening

The applicant described its screening approach for structural components in procedure LRPPG-03. For each structure within the scope of license renewal, LRP-PG-03 states that it is

necessary to evaluate the structure's structural components and commodities to determine

those subject to an AMR. The procedure also states that the screening process involves a

review of design-basis information to identify the specific structural components and

commodities that make up the structure. Section 5.1, "Screening of Structural Components and

Commodities," of LRP-PG-03, states 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 and are not subject to replacement based on qualified life or

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specified time period. The applicant noted that since structures are inherently passive, and,

with few exceptions, are long-lived, the screening of structural components and commodities is

based primarily on whether they perform an intended function. The applicant noted that

structural components and commodities often have no unique identifier. Therefore, the

applicant grouped structural components and commodities based on materials of construction;

The applicant identified these structural component groups in the associated AMR.

The staff determined that the applicant's screening criteria are consistent with the requirements

of 10 CFR 54.21 and are, therefore, acceptable. In particular, the screening process provides

reasonable assurance that passive, long-lived structural components within the scope of license

renewal would be subject to an AMR.

Conclusion

The staff determined that the applicant's structural component screening methodology is

consistent with the guidance contained in the SRP-LR and is capable of identifying those

passive, long-lived components within the scope of license renewal that are subject to an AMR.

2.1.3.2.3 Electrical and l&C Component Screening

The applicant described its screening approach for electrical components in procedure LRPPG-05. Procedure LRP-PG-05 states that it is not necessary to evaluate each electrical

systems within the plant to identify individual system intended functions. Rather, the applicant

implemented the spaces approach to identify all electrical component types and commodities

within the electrical systems of the plant to determine those subject to an AMR. Section 5.0,

"Instructions," of LRP-PG-05, discusses the use of the EPRI License Renewal Electrical

Handbook as a basis for identifying and classifying plant-specific electrical components into

commodity groups consistent with the guidance in NEI 95-10. Section 5.1, "Scoping

Considerations," of LRP-PG-05, identifies seven electrical commodity groups that potentially

require AMRs. The applicant identified these electrical commodity groups in the associated

AMRR. These seven categories include insulated cables and connectors (including fuse

holders), electrical portions of penetration assemblies, phase bus, -transmission conductors,

switchyard bus, high-voltage insulators, and uninsulated ground conductors. The applicant

then evaluated these commodity groupings to identify whether they are long-lived or subject to

replacement based on a qualified life or specified time period. The only electrical commodities

that meet the long-lived criterion are specifically identified as included within the Environmental

Qualification Program. All other components within these seven commodity groups are

included in subsequent AMRs.

The staff determined that the applicant's screening criteria are consistent with the requirements

of 10 CFR 54.21 and are, therefore, acceptable.: In particular, the screening process provides

reasonable assurance that passive, long-lived electrical component and commodity groups

within the scope of license renewal would be subject to an AMR.

Conclusion

The staff determined that the applicant's electrical and l&C screening methodology is consistent

with the guidance contained in the SRP-LR and is capable of identifying passive, long-lived

components within the scope of license renewal that are subject to an AMR.

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2.1.4 Evaluation Findings

The staff review of the information presented in Section 2.1 of the LRA, the supporting

information in the scoping and screening implementation procedures and reports, the

information presented during the scoping and screening methodology audit, and the applicant's

responses to the staff's RAls form the basis of the staff's safety determination. The staff

verified 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

10 CFR Part 54 and the staff's position on the treatment of nonsafety-related SSCs. On the

basis of this review, the staff concludes that there is reasonable assurance 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).

2.2 Plant-Level Scoping Results

In LRA Section 2.2, "Plant-Level Scoping Results," the applicant provided the results of its

scoping review. The staff reviewed this section of the LRA to determine whether there is

reasonable assurance that the applicant 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

The applicant first identified all plant systems and structures by using multiple sources of

documentation, including CLB references, the FDB, piping and instrumentation drawings

(P&lDs), and civil/structural plant layout drawings. The applicant then evaluated the identified

systems and structures against the criteria of 10 CFR 54.4(a). The applicant listed the systems

and structures that are within the scope of license renewal.

Tables 2.2-1 a, 2.2-1 b, and 2.2-3, of the LRA document the plant-level scoping results for

mechanical systems, electrical systems, and structures, respectively, that are within the scope

of license renewal. The applicant identified 47 mechanical systems, 45 electrical systems, and

18 structures within the scope of license renewal. Table 2.2-2 of the LRA identifies 20

mechanical systems that are not within the scope of license renewal. Table 2.2-4 of the LRA

identifies 43 structures or buildings that are not within the scope of license renewal. The

applicant did not exclude any electrical systems from the scope of license renewal.

2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.2, the contents of the CNP UFSAR, and the information

provided in the applicant's responses to the staff's RAIs to determine whether it excluded any

systems and structures required to perform intended functions from the scope of license

renewal. The staff conducted its review in accordance with Section 2.2 of the SRP-LR.

The staff's review of LRA Section 2.2 identified areas in which it needed additional information

to complete its evaluation of the applicant's plant-level scoping results. Therefore, the staff

issued RAIs to the applicant concerning specific issues to determine whether the applicant has

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properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of

10 CFR 54.21 (a)(1). The following describes the staff's RAls and the applicant's responses.

RAI 2.2-1

With respect to the scoping methodology, LRA Section 2.1.1 states the following:

Consistent with NEI 95-10, the scoping process used for the CNP license

renewal project began with a list of plant systems and structures,

determined the functions they perform, and then determined which

functions met any of the three criteria of 10 CFR 54.4(a). Functions that

meet any of the criteria are intended functions for license renewal, and

the systems and structures that perform these functions are included

within the scope of license renewal.

For the staff to determine that the applicant did not omit any SSCs that should be within the

scope of license renewal according to 10 CFR 54.4(a), the staff requested that the applicant

confirm whether all the SSCs in such systems and structures were included within the scope of

license renewal. If not, the staff requested that the applicant describe what SSCs were

excluded from the scope of license renewal.

In its response, dated January 14, 2004, the applicant stated the following:

To provide assurance that no structures, systems, and components that should

be within the scope of license renewal according to 10 CFR 54.4(a) were omitted

from the CNP license renewal scope, the response to this question addresses

the comprehensiveness of the CNP scoping and screening process.

All of the mechanical and electrical systems at CNP were reviewed for inclusion

in the scope of license renewal. Use of the CNP facility database, a

comprehensive database of plant equipment, provides assurance that all

systems are reviewed for inclusion in the scope of license renewal.

As discussed in LRA Section 2.1.1, the scoping process began with a list of plant

systems and structures. The functions performed by the plant systems and

structures were determined, then a determination was made as to which

functions met any of the three criteria of 10 CFR 54.4(a). Functions that meet

any of the criteria are intended functions for license renewal, and the systems

and structures that perform these functions are included within the scope of

license renewal. These systems and structures that perform intended functions

are indicated in the LRA in Table 2.2-1 a, Systems Within the Scope of License

Renewal Mechanical Systems, Table 2.2-1 b, Systems Within the Scope of

License Renewal Electrical Systems (Bounding Approach), and Table 2.2-3,

Structures Within the Scope of License Renewal. Systems and structures that

are not within the scope of license renewal are listed in the LRA in Table 2.2-2,

Systems Not Within the Scope of License Renewal, and Table 2.2-4, Structures

Not Within the Scope of License Renewal. The mechanical and electrical

system codes from the CNP facility database were included in LRA

Tables 2.2-1 a, 2.2-1 b, and 2.2-2.

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- _I I

To ensure comprehensive consideration of structures for inclusion in the scope

of license renewal, the structures listed in LRA Tables 2.2-3 and 2.2-4 were

identified from a review of current licensing basis documentation, including the

Updated Final Safety Analysis Report and civil/structural plant layout drawings.

The current license basis documentation was used in addition to the facility

database (FDB) since all structures are not listed in the facility database.

In conclusion, all components within the systems identified in LRA Tables 2.2-1a

and 2.2-1b, and all structures identified in LRA Table 2.2-3, were conservatively

considered to be within the scope of license renewal for the purposes of

identifying components and structures that are subject to AMR.

Based on its review of the response, the staff finds the applicant's response to RAI 2.2-1

acceptable because it clarifies the methodology used in the development of the list of SSCs, the

scoping process, and the use of supporting documentation. Therefore, the staff's concerns

described in RAI 2.2-1 are resolved.

RAI 2.2-3

In a comparison of the CNP units, the staff finds that, in general, the CNP LRA does not identify

design differences in the systems and components for CNP, Unit 1, compared to Unit 2. The

NRC licensed CNP, Units 1 and 2, approximately 3 years apart, and the units have a 5-percent

difference in rated thermal power.

Therefore, in RAI 2.2-3, the staff asked the applicant to provide a general description of the

major design differences between the systems and components of the two units. The staff

requested that the applicant explain how it addressed these differences in the scoping and

screening review process for the corresponding systems of the two units.

In its response, dated May 7, 2004, the applicant stated that the CNP units are essentially the

same. The applicant reviewed any differences in accordance with the established process for

scoping and screening. Sections 2 and 3 of the LRA address the differences as required. The

following summarizes the differences that are considered in the LRA:

The Unit 1 turbine generator was manufactured by the General Electric Company with

an electro-hydraulic type turbine control system. The Unit 2 turbine generator was

manufactured by Brown, Boveri and Company with a mechanical-hydraulic turbine

control system.

* Steam generators for Unit 2 were replaced in 1988. Unit 1 steam generators were

replaced in 2000.

* The Unit 1 refueling water storage tank is heated by means of heat tracing circuits. The

Unit 2 refueling water storage tank is heated by means of a pump that recirculates tank

water through two electric heaters.

* Reactor core at Unit 1 consists of a 15 X 15 array fuel assembly design, whereas the

Unit 2 core comprises of a 17 X 17 array fuel assembly.

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Based on its review, the staff finds the applicant's response to RAI 2.2-3 acceptable because

the applicant adequately described the major differences between the CNP units, as well as

identified differences that are considered in the LRA. Therefore, the staff's concern described

in RAI 2.2-3 is resolved.

RAI 2.2-4

Section 1.4 of the CNP UFSAR notes that the design of Unit 1 preceded the adoption of the

Appendix A, "General Design Criteria," to 10 CFR Part 50, and, therefore, the CNP plant is

designed and constructed to meet the intent of the proposed general design criteria (GDC),

dated July 11, 1967. Use of the preliminary version of the plant-specific design criteria (PSDC)

may have resulted in significant differences in the licensing bases for CNP, Units 1 and 2, from

later pressurized-water reactors (PWRs) of a similar design.

To facilitate its review, the staff requested that the applicant provide a summary description of

the impact of these differences on the CNP design, including the technical areas in which any

differences could affect the scoping and screening results for the two units.

In its response dated May 7, 2004, the applicant stated that the CNP PSDC define the principal

criteria and safety objectives for the CNP design. The PSDC discussed in Section 4 of the

UFSAR apply l&M's understanding of the intent of the GDC proposed by the Atomic Energy

Commission (AEC) in July 1967. The CNP PSDC, as presented in the preliminary safety

analysis report, were approved by reference when the AEC issued construction permits.

The applicant submitted the application for the operating license, including the final safety

analysis report (FSAR), on February 1, 1971, before the May 21, 1971, effective date of

Appendix A to 10 CFR Part 50. The AEC review ensured that, at a minimum, the CNP design

met the PSDC by evaluating the design against the proposed GDC. Section 3.1 of the

September 10, 1973, operating license SER documents this review and acknowledges that

CNP is not designed to, and I&M is not committed to, the "current general design criteria,"

although the design meets these criteria:

The Cook plant was designed and constructed to meet the intent of the

Proposed General Design Criteria, published July 11, 1967. The Final Safety -

Analysis Report had been filed with the Commission when revisions of the

General Design Criteria were published in February 1971 and July 7, 1971. We*

reviewed the plant design against the current General Design Criteria and we

believe that the design meets these criteria.

The applicant performed the license renewal IPA in accordance with the requirements of

10 CFR Part 54 and consistent with the guidance provided by NEI 95-10. This review does not

include a detailed comparison of the CNP design to the GDC in Appendix A to 10 CFR Part 50,

but rather assesses the existing plant design, as described in the CLB, to ensure that the SCs

requiring aging management are identified and that the effects of aging are effectively

managed to maintain the CLB.

As discussed in UFSAR Section 1.4.10, a number of specific aspects of the GDC in Appendix A

to 10 CFR Part 50 have become obligations or commitments applicable to the CNP design. If

these aspects were determined to be pertinent to the license renewal IPA, the LRA discusses

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or references them. For example, LRA Section 2.3.3.6 states that maintaining dose to control

room operators less than GDC-1 9 is a safety-intended function of the control room ventilation

system. In addition, LRA Section 4.7.1.2 discusses the leak-before-break (LBB) analysis of the

pressurizer surge line. This analysis credits provisions of GDC-4, "Environmental and Dynamic

Effects Design Basis," to exclude from the plant's design basis the dynamic effects associated

with postulated pipe rupture if the analysis approved by the NRC demonstrates that the

probability of pipe rupture is extremely low. Reference 4.7-3 of the LRA provides the NRC

approval of the LBB analysis.

In summary, the CNP design, as approved by the NRC in the September 10, 1973, operating

license SER, was determined to meet the GDC that were current at the time of issuance of the

operating license (i.e., GDC published in Appendix A to 10 CFR Part 50). I&M did not perform

a detailed comparison of the plant design to the GDC, but instead considered the plant design,

as described in the CLB, as the basis for the license renewal evaluations in the IPA. The LRA

and UFSAR Section 1.4.10 discuss specific cases in which l&M has committed to aspects of

the GDC in Appendix A to 10 CFR Part 50, as appropriate.

Based on its review, the staff finds the applicant's response to RAI 2.2-4 acceptable because

the applicant adequately explained how the differences in the design of Units 1 and 2 affected

the IPA. Therefore, the staff's concern described in RAI 2.2-4 is resolved.

RAI 2.2-5

Many LRA Section 2 tables (i.e., Tables 2.3.3-2, 2.3.3-3, and 2.3.4-3) list "fittings" as a

component type subject to an AMR having the intended function of a pressure boundary.

Fittings normally include piping system components such as elbows, tees, unions, reducers,

and caps. However, the corresponding LRA table for the other auxiliary systems and steam

and power conversion system (i.e., Tables 2.3.3-5, 2.3.3-6, 2.3.3-11, 2.3.4-1, 2.3.4-2, and

2.3.4-4) do not include the component type "fittings," even though fittings are an integral part of

these systems. In this RAI, the staff requested that the applicant identify components that were

considered in the LRA tables as part of the component group fittings," and explain why some

of the LRA Section 2 tables did not include the component type "fittings."

In its response, dated May 7, 2004, the applicant stated:

Piping system components such as elbows, tees, unions, reducers, and caps,

are included in the component type "Fittings." In some of the LRA Section 2

(and Section 3) tables, these piping system components were included in

component type "Piping." Fittings were included separately in those LRA tables

where a fittings listing was not identical to piping or manifold (piping) listings in

the table (i.e., differences exist between the materials or environments applicable

to the piping/manifold and those applicable to the fittings). Where the

material/environment combinations applicable to the fittings are the same as the

piping listings in a table, a separate listing is not necessary. Regardless of which

component type was used for fittings that are an integral part of a system, all

material and environmental combinations present in passive, long-lived

components that perform or support an intended function within the system are

reviewed and appropriately included for aging management.

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Based on its review, the staff finds the applicant's response to RAI 2.2-5 acceptable because

the applicant adequately explained how the component type "fitting§" includes fittings of a

material and environment combination different than that of the "piping" component type.

Therefore, the staff's concern described in RAI 2.2-5 is resolved.

RAI 2.2-6

License renewal drawings for the essential service water (ESW) system for CNP, Units 1 and 2,

(LRA-1 -5113 and LRA-2-5113, respectively) show radiation monitoring alarms at locations M3

and M6. Similarly, the Units 1 and 2 license renewal drawings of the CCW system (LRA-15135

and LRA-25135, respectively) show radiation monitoring alarms at locations J6 and J7. In RAI

2.2-6, the staff asked the applicant to clarify whether these alarms penetrate the pressure

boundary of the system piping. If they do, as recommended in Table 2.1-5 of the SRP-LR and

Appendix B to NEI 95-10, Revision 3, the staff requested that the applicant identify the radiation

monitoring alarms for the auxiliary systems that support the intended function of maintaining the

pressure boundary and, thus, are within the scope of license renewal and subject to an AMR, in

accordance with the requirements of 10 CFR 54.4(a)(1)(ii) and 10 CFR 54.21 (a)(1).

In its response, dated May 7, 2004, the applicant stated that the review of the ESW and CCW

systems includes the pressure boundary passive mechanical component for these radiation

detectors under the component type "detector well" in LRA Tables 3.3.2-2 and 3.3.2-3.

Based on its review, the staff finds the applicant's response to RAI 2.2-6 acceptable because

the applicant adequately explained how the component type "detector well" in the ESW and

CCW systems includes the pressure boundary portions of the radiation detectors. Therefore,

the staff's concern described in RAI 2.2-6 is resolved.

2.2.3 Conclusion

The staff reviewed LRA Section 2.2 and the supporting information in the CNP UFSARs to

determine whether the applicant had omitted any structures and systems from the scope of

license renewal. As a result of this review, the staff did not identify any omissions. On the

basis of this 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.

2.3 System Scoping and Screening Results-Mechanical Systems

This section documents the staff's review of the applicant's scoping and screening results for

mechanical systems. Specifically, this section discusses the following mechanical systems:

* reactor coolant system

* engineered safety features

* auxiliary systems

* steam and power conversion systems

In accordance with the requirements stated in 10 CFR 54.21(a)(1), the applicant must identify

and list passive, long-lived mechanical systems and components that are within the scope of

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license renewal and subject to an AMR. To verify that the applicant properly implemented its

methodology, the staff focused its review on the implementation results. This approach allowed

the staff to confirm that the applicant did not omit any mechanical system components that

meet the scoping criteria and are subject to an AMR.

Staff's Evaluation Methodology

The staff performed its evaluation of the information provided in the LRA in the same manner

for all mechanical systems. The review sought to determine if the applicant identified

components and supporting structures for specific mechanical systems that appear to meet

scoping criteria specified in 10 CFR Part 54 as within the scope of license renewal in

accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to

verify that all long-lived, passive components are subject to an AMR in accordance with

10 CFR 54.21 (a)(1).

Scoping To perform its scoping evaluation, the staff reviewed the applicable LRA section and

associated component drawings, focusing the review on components that the applicant had not

identified as within the scope of license 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

the LRA specifies all intended functions delineated under 10 CFR 54.4(a). If the staff identified

omissions, the staff requested additional information to resolve the discrepancy.

Screening 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, 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 components that do not meet either of

these criteria, the staff sought to confirm that these mechanical system components are subject

to an AMR, as required by 10 CFR 54.21 (a)(1). If the staff identified discrepancies, it requested

additional information to resolve them.

The applicant did not supply marked drawings or any other means of identifying the specific

components that are within the scope of license renewal meeting the criteria of

10 CFR 54.4(a)(2). Instead, it supplied a rollup of component types that represent those

components meeting the criteria of 10 CFR 54.4(a)(2). Section 2.3.1 of the SRP-LR states the

following:

For a mechanical system that is within the scope of license renewal, the

applicant should identify the portions of the system that perform an intended

function, as defined in 10 CFR 54.4(b). The applicant may identify these

particular portions of the system in marked-up piping and instrument diagrams

(P&IDs) or other media. This is "scoping" of mechanical components in a

system to identify those that are within the scope of license renewal for a

system.

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Because the information that the applicant provided deviated from the information that the staff

needed to complete its review, the staff requested additional information- about the methodology

used for identifying these components.

RAI 2.3-1

Section 2.1.2.1.2, Identifying Components Subject to Aging Management Review," of the LRA

states that, "[license] renewal drawings were created by marking mechanical flow diagrams to

indicate only those components within the system evaluation boundaries that require an aging

management review." However, the highlighted portions of license renewal drawings are

bounded by a flag, which the legend of the drawing defines as the license renewal boundary.

As such, the license renewal drawings indicate that the highlighted portions represent SSCs

that are within the scope of license renewal. The staff asked the applicant to clarify this

apparent discrepancy by confirming whether the highlighted portions represent SSCs that are

(1) within the scope of license renewal or (2) within the scope of license renewal and subject to

AMR.

In its response dated January 14, 2004, the applicant stated the following:

The highlighted portions of the license renewal drawings represent systems,

structures, and components that are within the scope of license renewal and

subject to AMR. This is not indicative of a discrepancy between the text in LRA

Section 2.1.2.1.2 and the manner in which the license renewal drawings were

highlighted.

LRA Section 2.1.2.1.2, "Identifying Components Subject to Aging Management

Review," states the following: "[license] renewal drawings were created by

marking mechanical flow diagrams to indicate only those components within the

system evaluation boundaries that require an aging management review." The

license renewal boundary may be defined as the separation point between the

portion of the system that requires an AMR (highlighted portion) and the portion

of the system that does not require an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3-1 acceptable because it

clarifies information in LRA Section 2.1.2.1.2. Therefore, the staff's concern described in RAI

2.3-1 is resolved.

2.3.1 Reactor Coolant System

Unless otherwise stated, the RCS description and the component descriptions apply to both

CNP Units 1 and 2.

The RCS is designed to contain pressurized treated (borated) water while transporting heat

from the reactor core to the steam generators. The system consists of four similar heat transfer

loops connected in parallel to the reactor vessel. Each loop contains a RCP and a steam

generator. In addition, the system includes a pressurizer, a pressurizer relief tank, and the

necessary interconnecting piping and instrumentation. All major components are located in the

reactor containment.

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During operation, the RCPs circulate pressurized water through the reactor vessel and the

reactor coolant loops. The water, which serves as a coolant, moderator, and solvent for boric

acid (chemical shim control), is heated as it passes through the core. The water then flows to

the steam generators, where the heat is transferred to the secondary system. The coolant exits

the steam generators, returning to the RCPs to repeat the cycle.

System pressure is controlled in the pressurizer, where electrical heaters and water sprays

maintain water and steam in equilibrium. The pressurizer lower half is filled with saturated

water, and the top half is filled with saturated steam. Pressurizer heaters in the liquid space

form steam to raise and maintain pressure. Pressurizer sprays in the steam space condense

steam to lower pressurizer pressure.

Three spring-loaded safety valves and three power-operated relief valves (PORVs) connected

to the pressurizer provide overpressure protection. The low-temperature overpressure

protection system (LTOPS) provides overpressure protection during low-temperature operation

of the RCS, when the reactor vessel is vulnerable to brittle fracture failure. The LTOPS is a

combination of automatic actuation devices, passive relief devices, and administrative controls

designed to ensure that RCS pressure is maintained within the limits defined in Appendix G to

10 CFR Part 50.

A material compatible with the system temperature insulates components and piping in the

RCS to reduce heat loss. Insulation material used for RCS components has low soluble

chloride and other halide content to minimize the possibility of stress-corrosion cracking (SCC)

of stainless steel.

The RCS is within the scope of license renewal as a safety related system, as it is in

accordance with 10 CFR 54.4(a)(1). Certain nonsafety related portions of the system are within

the scope of license renewal as potentially affecting safety related components, which is in

accordance with 10 CFR 54.4(a)(2). Pursuant to 10 CFR 54.4(a)(3), the RCS is within the

scope of license renewal for PTS requirements, SBO (as the RCS pressure boundary must be

maintained during SBO), and FP for safe shutdown following a fire.

The applicant used the RCS intended function (i.e. to provide a pressure and fission product

barrier) to establish the CNP RCS Class 1 evaluation boundary. The evaluation boundary

includes the reactor vessel internals (RVI). The CNP RCS Class 1 evaluation boundary

corresponds to RCS pressure boundary components within the ASME Code, Section Xl,

Subsection IWB, inspection boundary and includes the non-Class 1 instrumentation and vent

lines attached to RCS components. The evaluation boundary also includes the secondary side

of the steam generators (i.e., vessel shell and nozzles attached to the vessel that are inspected

in accordance with ASME Code, Section Xl, Subsection IWC). Components within the RCS

Class 1 evaluation boundary are hereafter referred to as Class 1 components.

The following Class 1 components support the RCS system intended functions and are subject

to an AMR:

* reactor vessel and control rod drive mechanism pressure boundary

* reactor vessel internals

* Class 1 piping, valves, and reactor coolant pumps

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* pressurizer

* steam generators

The RCS Class 1 piping evaluation boundary extends into portions of ancillary systems

attached to the RCS. The Class 1 components of the systems listed below are evaluated with

the RCS. The non-Class 1 portions of the systems listed below are evaluated in the referenced

sections of this SER:

* chemical and volume control system (Section 2.3.3.5)

* emergency core cooling system (Section 2.3.2.3)

* nuclear sampling (Section 2.3.3.1 1)

The RCS evaluation includes the following systems in their entirety:

* control rod drives (included with the reactor vessel)

* reactor vessel level instrumentation system (RVLIS) (included with RCS piping)

2.3.1.1 Reactor Vessel and Control Rod Drive Mechanism Pressure Boundary

2.3.1.1.1 Summary of Technical Information in the Application

In Section 2.3.1.2 of the LRA, the applicant described the reactor vessel and control rod drive

mechanism (CRDM) pressure boundary. The reactor vessel contains the nuclear fuel core,

core support structures, control rods, and other parts directly associated with the core. The

vessel is cylindrical with a welded hemispherical bottom head and a removable, hemispherical

upper head. The vessel has four inlet nozzles and four outlet nozzles with weld-deposited

cladding on inner surfaces. These eight nozzles are arranged circumferentially around the

vessel at the nozzle belt of the vessel, below the vessel closure flange but above the top of the

core.

The CRDM nozzles with attached nozzle adapters and a vent pipe penetrate the reactor vessel

closure heads. Partial penetration welds attach these nozzles to the head. The pressureretaining items associated with the CRDMs include pressure housings and rod travel housings.

Each CRDM pressure housing is threaded onto the adapter on top of the reactor pressure

vessel (RPV) and seal welded or mechanically clamped. The closure at the top of the rod travel

housing includes a threaded cap with a canopy seal weld or conoseal joint.

Two hollow, metallic O-rings seal the reactor vessel closure head. Two leak-off connections,

one between the inner and outer ring and one outside the outer ring, detect seal leakage. The

0-rings are replaced regularly and are therefore not subject to an AMR.

Nozzle and conduit assemblies, through which the in-core instrumentation thimble tubes are

inserted into the reactor core, penetrate the bottom head.

The CNP reactor vessels and CRDMs were constructed in accordance with the requirements of

ASME Code, Section IlIl.

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Section 2.3.1.3 of the LRA discusses the reactor vessel internals, and LRA Section 2.3.1.4

discusses the RCS piping attached to reactor vessel safe ends. Section 4.2.2.1, "Reactor

Vessel," of the CNP UFSAR provides additional information regarding the CNP reactor vessel.

In Table 2.3.1-1 of the LRA, the applicant identified the reactor vessel and CRDM pressure

boundary component types that are within the scope of license renewal and subject to an AMR,

including the bottom head, shell-nozzle course, upper head, inlet nozzles, outlet nozzles, shell

rings, weld buildup support pads (external attachment), inlet nozzle safe ends, outlet nozzle

safe ends, vessel flange, closure head flange, closure studs, closure nuts, washers, CRDM

nozzles, CRDM housing adapter, in-core instrumentation nozzles, in-core instrumentation

nozzle safe ends, bottom-mounted instrumentation (BMI) thimble guide tubes, BMI thimble

tubes and bullet plugs, thimble seal table, core support lugs, vent line (nozzle and elbow), vent

line safe end, CRDM housing, core exit thermocouple nozzle assembly, holddown nut,

compression collar and lockwasher, CRDM housing cap, lifting lugs, ventilation shroud support

ring, and flange leak tubes.

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.1.2, 2.3.1.3, and 2.3.1.4 and CNP UFSAR Section 4.2.2.1

to determine whether the applicant identified the reactor vessel and CRDM pressure boundary

system components within the scope of license renewal and subject to an AMR. 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 verify that the applicant did

not inadvertently omit from the scope of license renewal any components with intended

functions delineated in 10 CFR 54.4(a). The staff then reviewed those components that the

applicant identified as within the scope of license renewal to verify that it 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, the staff needed additional information to complete its

evaluation of the applicant's scoping and screening results. Therefore, by letter to the applicant

dated May 10, 2004, the staff issued an RAI to assist the staff in determining 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 following paragraphs describe the staff's RAI and the applicant's

related response.

Note 1 in Table 2.3.1.2-1 of the LRA states that although the vessel lifting lugs do not directly

support an intended function, the table includes them for completeness. However, the staff's

position is that the subject component should be within the scope according to

10 CFR 54.4(a)(2) because its failure may prevent some of the safety related components from

performing their intended functions if the RPV head drops while being lifted. In RAI 2.3.1.2-1,

the staff requested that the applicant state the basis, pursuant to 10 CFR Part 54, on which it

determined components (specifically vessel lifting lugs) to be within scope and requiring aging

management.

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In its response dated May 20, 2004, the applicant stated that although the safety related reactor

vessel head (RVH) is credited for performing a pressure boundary intended function, the RVH

lifting lugs are not relied on to support this license renewal intended function. Since the lifting

lugs are part of the RVH, the applicant considered them to be safety related and included them

within the scope.

Based on its review, the staff finds the applicant's response to RAI 2.3.1.2-1 acceptable,

because the applicant included the components within the scope requiring an AMR and

identified the component type in the LRA which includes the subject components. Therefore,

the staff's concerns described in RAI 2.3.1.2-1 are resolved.

2.3.1.1.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI response, the staff did not identify any omissions or discrepancies in

the applicant's scoping and screening results for the SCs of the reactor vessel and CRDM

system. Therefore, the staff concludes that the applicant has adequately identified the reactor

vessel and CRDM system SCs 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 and CRDM

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

2.3.1.2 Reactor Vessel Internals

2.3.1.2.1 Summary of Technical Information in the Application

In Section 2.3.1.3 of the LRA, the applicant described the reactor vessel internals (RVI) which

consist of the lower core support structure (including the entire core barrel, thermal shield, and

baffle/former assembly), the upper core support, and the in-core instrumentation support

structures. Reactor coolant flows from the vessel inlet nozzles down the annulus between the

core barrel and the vessel wall, then into a plenum at the bottom of the vessel. It then reverses

direction and flows up through the core support and through the lower core plate. After passing

through the core, the coolant enters the region of the upper support structure, then flows

radially to the core barrel outlet nozzles and directly through the vessel outlet nozzles.

Reactor vessel internals perform the following functions:

* provide support and orientation for the reactor core

* provide support, orientation, guidance, and protection of the control rod assemblies

* direct reactor coolant flow past the reactor core

* provide support, guidance, and protection for the in-core instrumentation

* limit the core support structure displacement

* provide gamma and neutron shielding for the reactor pressure vessel

The applicant reviewed the current design and operation of the RVI using the process

described in LRA Section 2.3.1.1 and confirmed that the CNP RVI are bounded by the

description provided in WCAP-14577-A. The component intended functions for the RVI are

consistent with the intended functions identified in WCAP-14577-A. The NRC review of WCAP14577-A resulted in applicant action items, which are documented in the corresponding NRC

safety evaluation (SE), dated February 10, 2001. Table 2.3.1-6 of the LRA provides CNP2-49
- _-' 1'

specific responses to those applicant action items relevant to the identification of RVI

components subject to an AMR. Section 3.2.1 (Unit 1), "Mechanical Design and Evaluation,"

and Section 3.2.2 (Unit 2), "Reactor Vessel Internals," of the CNP UFSAR provide additional

information regarding the CNP RVI.

In Table 2.3.1-2 of the LRA, the applicant identified the RVI component types that are within the

scope of license renewal and subject to an AMR for the lower core support structure, including

the core barrel (barrel, flange, outlet nozzle, and fasteners), core former plates, core baffle

plates, core former bolts, core baffle bolts, lower core plate, lower support columns, diffuser

plate, lower support plate, lower core plate support column cap, secondary core support

assembly (energy absorbers), clevis insert block and fastener, and thermal shield.

For the upper core support structure, the applicant identified the upper support plate, deep

beam sections, upper support columns, support column bolts (upper and lower), upper core

support column mixing device, upper core support column orifice base, upper core plate, upper

core plate alignment pins, radial keys, holddown spring, control rod guide tube pin, fuel

assembly guide pin, and guide tube assemblies.

For the in-core instrumentation support structure, the applicant identified the upper system

(thermocouples) and lower system (flux thimbles).

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3 and CNP UFSAR Sections 3.2.1 (Unit 1) and 3.2.2

(Unit 2) to determine whether the applicant identified the RVI system components within the

scope of license renewal and subject to an AMR. The staff used the evaluation methodology

described in Section 2.3 of this SER. The staff conducted its review in accordance with the

guidance in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 within the scope of license renewal

to verify that no passive and long-lived components that should be subject to an AMR in

accordance with the requirements of 10 CFR 54.21(a)(1) were omitted.

In reviewing LRA Section 2.3.1.3, the staff identified an area in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, the staff issued an RAI concerning the specific issues 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 following paragraphs describe the staff's RAI and the applicant's

related response.

Chapter 3 of the UFSAR (page 11 for Unit 1 and page 29 for Unit 2) states that a small amount

of inlet water is directed into the vessel head plenum to provide cooling of the vessel head.

According to WCAP-14577-A, the components associated with this cooling system should be

within the scope of license renewal as requiring aging management. Because Table 2.3.1-2 of

the LRA does not identify the subject components, the staff asked the applicant in RAI 2.3.1.3-1

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to confirm whether the components associated with RPV head cooling system are within scope

as requiring aging management.

In its response dated May 20, 2004, the applicant stated that to provide vessel head plenum

cooling, a small amount of bypass flow is directed from the inlet downcomer into the upper

head. The flowpath for this bypass flow consists of 16 spray holes located in the flange of the

core barrel. Similar spray holes are provided at corresponding locations in the upper support

plate. These spray holes are located outside the outer diameter of the holddown spring,

allowing a small, unimpeded bypass flow from the inlet downcomer below the core barrel

flange, through the annulus outside of the holddown spring, and up through the upper support

plate into the upper head plenum. The applicant clarified that at CNP, the spray holes are

included with the component types "core barrel" and "upper support plate," and are listed as

subject to an AMR in LRA Tables 2.3.1-2 and 3.1.2-2. Based on its review, the staff finds the

applicant's response to RAI 2.3.1.3-1 acceptable, because the applicant included the

components as within scope and as requiring an AMR and identified the component type in the

LRA which includes the subject components. Therefore, the staff's concerns described in RAI

2.3.1.3-1 are resolved.

2.3.1.2.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI response, the staff did not identify any omissions or discrepancies in

the applicant's scoping and screening results for the SCs of the RVI system. Therefore, the

staff concludes that the applicant has adequately identified the RVI system SCs that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the RVI system 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 2.3.1.4 of the LRA, the applicant described the Class 1 piping, valves, and RCP.

The RCS Class 1 piping and associated pressure boundary components consist of the

following:

* primary loop piping interconnecting the reactor vessel with the steam generator and

RCP in each loop

* pressurizer surge, spray, and relief lines

* auxiliary spray line

* normal and alternate charging lines

* letdown and excess letdown line

* residual heat removal lines

* safety injection lines

* accumulator lines

* sample/instrument lines (includes RVLIS)

* vent pipe from the reactor vessel head

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-

resistance temperature detector bypass lines, loop bypass lines, direct immersion

resistance temperature detectors, thermowells, sample and spray scoops, and reactor

vessel flange leak-off lines

For convenience, this section includes portions of RCS instrumentation and sampling tubing,

such as the reactor coolant pressure boundary items (valves and tubing) downstream of the

instrument root valves. The pressure-retaining portion of Class 1 valves consists of the valve

body, bonnet, and closure bolting. The RCS Class 1 valves are welded in place, with the

exception of the pressurizer safety valves, which have flanged connections.

The following portions of the RCPs perform a pressure boundary function:

* pump casings

* main closure flanges

* seals

* thermal barrier coil heat exchangers

* pressure-retaining closure bolting

The applicant periodically monitors, inspects, and replaces (as required) the RCP seals;

therefore, they are not subject to an AMR.

Class 1 piping is designed and constructed in accordance with United States of America

Standard (USAS) B31.1. The RCS valves are designed and constructed to ASME/American

National Standards Institute (ANSI) B-16.5 or Manufacturers Standardization Society of the

Valves and Fittings Industry (MSS)-SP-66, and ASME Code, Section III. The RCPs are

designed and constructed using ASME Code, Section 1II, as a guide. These codes are

consistent with WCAP-14575-A.

The applicant reviewed the current design and operation of the reactor coolant piping using the

process described in Section 2.3.1.1 of the LRA. This review confirmed that the CNP Class 1

piping, valves, and RCPs are bounded by the description provided in WCAP-1 4575-A with

regard to the following:

* design criteria and features

* materials of construction

* fabrication techniques

* installed configuration

* modes of operation

* environments/exposures

The component intended functions are consistent with the intended functions identified in

WCAP-14575-A. The NRC review of WCAP-14575-A resulted in applicant action items, which

are documented in the corresponding NRC SE, dated November 8, 2000. Table 2.3.1-7 of the

LRA provides CNP-specific responses to those applicant action items relevant to the

identification of reactor coolant piping components subject to an AMR.

The following sections of the CNP UFSAR provide additional information regarding the CNP

Class 1 piping, valves, and RCPs:

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* Section 4.2.2.5, 'Reactor Coolant Pump"

* Section 4.2.2.6, "Reactor Coolant System Vents"

* Section 4.2.2.7, "Reactor Coolant Piping"

* Section 4.2.2.8, "Valves"

In Table 2.3.1-3 of the LRA, the applicant identified the Class 1 piping component types that are

within the scope of license renewal and subject to an AMR, including hot-leg pipe and fittings,

cold-leg pipe and fittings, crossover leg pipe and fittings, pressurizer surge line, pipe and fittings

(including blind flanges) nominal pipe size (NPS) 4", pipe and fittings (including blind flanges)'

less than NPS 4", branch nozzles NPS 4", branch nozzles less than NPS 4N (includes sample

and spray scoops, thermowells, and immersion resistance temperature detectors), thermal

sleeves, and orifices.

The applicant also identified Class 1 valve component types, including Class 1 valve bodies and

bonnets (greater than or equal to 2.5"), Class 1 valve bodies and/or bonnets (less than or equal

to 2"), and bolting material (for valves and blind flanges), as being within the scope of license

renewal and subject to an AMR.

Finally, the applicant identified RCP component types, including casing, main closure flange,

main flange bolts, and thermal barrier heat exchanger as being within the scope of license

renewal and subject to an AMR.

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4 and CNP UFSAR Sections 4.2.2.5, 4.2.2.6, 4.2.2.7, and

4.2.2.8 to determine whether the applicant identified the Class 1 piping, valves, and RCP

system components within the scope of license renewal and subject to an AMR. 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 to verify 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 within the scope of license renewal

to verify that no passive and long-lived components that should be subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1) were omitted.

In reviewing LRA Section 2.3.1.4, the staff identified two areas in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, by letter to the applicant dated May 10, 2004, the staff issued RAls concerning these

issues 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 following paragraphs

describe the staff's RAls and the applicant's related responses.

RAI 2.3.1.4-1

The staff's position is that unless the applicant provides plant-specific justification, the reactor

vessel flange leak-off lines should be within scope and require aging management. In RAI

2.3.1.4-1, the staff requested the applicant to confirm whether the component types listed in

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Table 2.3.1-3 of the LRA include the subject components. If not, then the staff asked the

applicant to identify the subject components as within scope and requiring aging management

or provide a plant-specific justification.

In its response dated May 20, 2004, the applicant stated that the flange leak-off lines are

included within the scope of license renewal and require an AMR. The component type "flange

leak tubes" listed in LRA Table 2.3.1-1 includes the flowpath from the O-ring groove to the outer

surface of the reactor vessel flange. Downstream of the outer surface of the reactor vessel,

license renewal drawings LRA-1 -5128 and LRA-2-5128 show the flange leak-off lines at

location G5. Table 2.3.1-3 includes them as the following component types:

* piping and fittings (including blind flanges) less than NPS 4"

* Class 1 valve bodies and/or bonnets less than or equal to 2"

Based on its review, the staff finds the applicant's response to RAI 2.3.1.4-1 acceptable,

because the applicant included the components within the scope of license renewal requiring an

AMR and identified the component type in the LRA which includes the subject components.

Therefore, the staff's concern described in RAI 2.3.1.4-1 is resolved.

RAI 2.3.1.4-2

The staff also requested additional information regarding the RCP lubricating oil collection

subsystem which is regulated pursuant to 10 CFR Part 50, Appendix R, 111.0. This regulation

indicates that the RCP lubricating oil collection subsystem is designed to collect oil from the

RCPs and drain it to a collection tank to prevent a fire in the containment building during normal

plant operations. The staff's maintains that the subsystem and the tank should be within the

scope of 10 CFR Part 54 as requiring aging management. However, LRA Table 2.3.1-3 did not

identify the subject components; therefore, in RAI 2.3.1.4-2, the staff asked the applicant to

provide an explanation.

In its response dated May 20, 2004, the applicant stated that the lubricating oil collection

system is a non-Class 1 system with an intended function of meeting FP requirements;

therefore, the FP system AMR includes the lubricating oil collection system. Table 2.3.3-7 of

the LRA lists the system component types "fittings," "piping," "tank," and 'valve" as subject to an

AMR for the FP system. Table 3.3.2-7 of the LRA includes components in the lubricating oil

collection system with the external and internal environments of lubricating oil and borated

water leakage, which LRA Table 3.0-1 identifies as environments specific to the lubricating oil

collection system.

Based on its review, the staff finds the applicant's response to RAI 2.3.1.4-2 acceptable,

because the applicant included the components as within the scope of license renewal and

requiring an AMR and identified the component type in the LRA which includes the subject

components. Therefore, the staff's concern described in RAI 2.3.1.4-2 is resolved.

2.3.1.3.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the Class 1 piping, valves, and

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RCP system. Therefore, the staff concludes that the applicant adequately identified the Class 1

piping, valves, and RCP system SCs that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant adequately identified the Class 1 piping, valves, and

RCP system SCs 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 2.3.1.5 of the LRA, the applicant described the pressurizer. The pressurizer is a lowalloy steel (LAS), vertically oriented, cylindrical vessel with hemispherical top and bottom heads

and austenitic stainless steel cladding on interior surfaces that are exposed to the reactor

coolant. The pressurizer is connected to the RCS on one of the hot legs of a coolant loop.

Electrical heaters are installed through the bottom head of the pressurizer, while the spray

nozzle, relief, and safety valve connections are located in the top head of the pressurizer. The

pressurizer includes the vessel, attached nozzles, and safe ends out to the connection with

RCS piping. Section 2.3.1.4 of the LRA discusses the valves (i.e., safety and relief), instrument

lines, and other piping connected to the pressurizer.

The applicant reviewed the current design and operation of the Unit 1 and 2 pressurizers using

the process described in Section 2.3.1.1 of the LRA. It confirmed that both CNP pressurizers

are bounded by the description provided in WCAP-14574-A. The pressurizers were designed

and constructed in accordance with ASME Code, Section 1II, which is consistent with WCAP14574-A. The component intended functions for the pressurizers include the intended functions

identified in WCAP-1 4574-A.

In addition to the functions identified in WCAP-1 4574-A, the applicant identified an additional

function of pressure control. The pressurizer spray head and heaters provide pressure control

during certain DBEs. The NRC review of WCAP-1 4574-A resulted in applicant action items,

which are documented in the corresponding NRC SE, dated October 26, 2000. Table 2.3.1-8

of the LRA provides the CNP-specific responses to those applicant action items relevant to the

identification of pressurizer components subject to an AMR. Section 4.2.2.2, "Pressurizer," of

the CNP UFSAR provides additional information regarding the CNP pressurizers.

In Table 2.3.1-4 of the LRA, the applicant identified the pressurizer component types that are

within the scope of license renewal and subject to an AMR, including lower head, shell, upper

head, surge nozzle, spray nozzle, relief nozzle, safety nozzle, surge nozzle safe end, spray

nozzle safe end, relief nozzle safe end, safety nozzle safe end, surge and spray nozzle thermal

sleeve, heater well nozzles and coupling, immersion heater sheaths, heater support plates,

heater support plate brackets, heater support plate bracket bolts, spray head, spray head

locking bar, spray head coupling, support skirt and flange, seismic lugs, valve support bracket

lugs, instrument nozzles and couplings, manway insert, manway forging, manway cover, and

manway cover bolts/studs.

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.5 and CNP UFSAR Section 4.2.2.2 to determine whether

the applicant identified the pressurizer system components within the scope of license renewal

and subject to an AMR. The staff used the evaluation methodology described in Section 2.3 of

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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 to verify 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 within the scope of license renewal

to verify that no passive and long-lived components that should be subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1) were omitted.

In reviewing LRA Section 2.3.1.5, the staff needed additional information to complete its

evaluation of the applicant's scoping and screening results. Therefore, the staff issued RAls

concerning these specific issues 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

following paragraphs describe the staff's RAls and the applicant's related responses.

RAI 2.3.1.5-1

In the past, the applicant observed intergranular and transgranular type SCC in the welded

section of pressurizer instrumentation nozzles in Westinghouse PWRs. In RAI 2.3.1.5-1, the

staff asked the applicant to confirm whether it performed an AMR for the welded portion of the

instrumentation nozzles.

In its response dated May 20, 2004, the applicant stated that it performed an AMR for the

attachment welds of the pressurizer instrument nozzles at CNP. Similar to other pressurizer

nozzles such as the spray, surge, and relief nozzles, it reviewed the instrument nozzle

attachment welds with the welded item itself and included them in the component type

"instrument nozzles and couplings" in LRA Table 2.3.1-4. The AMR results for pressurizer

instrument nozzles and couplings, as listed in LRA Table 3.1.2-4, include the attachment welds.

Based on its review, the staff finds the applicant's response to RAI 2.3.1.5-1 acceptable

because the applicant included the components as within the scope of license renewal and

requiring an AMR and identified the component type in the LRA that includes the subject

components. Therefore, the staff's concern described in RAI 2.3.1.5-1 is resolved.

RAI 2.3.1.5-2

Drawing 5128A and Table 2.3.1-4 in the LRA do not include the pressurizer relief/quench tank

as within scope. For the staff to determine whether the exclusion is justified, the staff asked, in

RAI 2.3.1.5-2, the applicant to provide the following additional information:

(a) Does the failure of pressurizer relief tank prevent effective pressure

control or prevent depressurization through the relief/safety valves?

(b) In the event the relief tank is not functional, and as a result, high pressure

and high velocity steam need to be discharged into the containment, what

are the consequences? The response should include discussions on

potential of failure of other safety related components by the discharging

steam.

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In its response dated May 20, 2004, the applicant stated the following:

(a) The function of the pressurizer relief tank (PRT), as described in UFSAR

Section 4.2.2.3, is to condense and cool the discharge from the

pressurizer safety and relief valves, as well as several smaller relief

valves. By means of its connection to the waste disposal system, the

PRT also provides a means for removing any non-condensable gases,

which might collect in the pressurizer, from the reactor coolant system.

The PRT does not serve a pressurizer pressure control or

depressurization prevention function.

(b) The consequences of a steam discharge from the PRT to the

containment atmosphere are enveloped by various safety analyses

described in detail in each unit's UFSAR Chapter 14. UFSAR Section

14.2.5 discusses the analysis of a steam pipe rupture. UFSAR

Section 14.3.1 describes the analysis for a large break loss of coolant

accident. Unit 2 UFSAR Section 14.4.11, which includes the Unit 1

analysis, states that equipment inside containment must be qualified to

demonstrate that it can perform its safety related function following a

high-energy line break (HELB). Unit 2 UFSAR Tables 14.4.2.1 and

14.4.2.1A include pressurizer safety and relief valves, and supporting

components, in the equipment required for shutdown following a HELB.

The PRT is not included in the lists of equipment in UFSAR Tables

14.4.2.1 or 14.4.2.1A.

Based on its review, the staff finds the applicant's response to RAI 2.3.1.5-2 acceptable

because, as described above, the applicant explained why the component does not meet the

scoping and screening criteria outlined in 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1) and, thus, is

not required to be in the scope of license renewal. Therefore, the staff's concern described in

RAI 2.3.1.5-2 is resolved.

RAI 2.3.1.5-3

Table 2.3.1-4 of the LRA listed spray head as a component type subject to an AMR with an

intended function of pressure control. Section 2.3.1.5, Page 2.3-10, of the LRA states that the

spray head and heaters provide pressure control during certain DBEs. However, LRA drawing

5128A shows the components as not within scope. In RAI 2.3.1.5-3, the staff asked the

applicant to clarify this apparent inconsistency.

In its response dated May 20, 2004, the applicant stated that the pressurizer spray head is

within scope and that it performed an AMR on this item. This review resulted in LRA Tables

2.3.1-4 and 3.1.2-4 listing the component types "spray head," "spray head locking bar," and

"spray head coupling." The applicant inadvertently omitted the highlighting of the spray head on

license renewal drawings LRA-1-5128A and LRA-2-5128A.

Based on its review, the staff finds the applicant's response to RAI 2.3.1.5-3 acceptable

because the applicant included the components as within scope and requiring an AMR and

identified the component type in the LRA which includes the subject components. Therefore,

the staff's concern described in RAI 2.3.1.5-3 is resolved.

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2.3.1.4.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the pressurizer system.

Therefore, the staff concludes that the applicant adequately identified the pressurizer system

SCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant adequately identified 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 2.3.1.6 of the LRA, the applicant described the steam generators. The steam

generators are vertical shell and U-tube heat exchangers with integral moisture separating

equipment. Reactor coolant flows through the inverted U-tubes, entering and leaving through

nozzles located in the hemispherical bottom head of the steam generator. A vertical partition

plate extending from the head to the tubesheet divides the head into inlet and outlet chambers.

Feedwater enters the steam generators and is distributed through a feedwater ring located just

below the moisture separators. Feedwater flows down between the steam generator shell and

tube bundle wrapper and into the tube bundle just above the tubesheet. Steam is generated on

the shell side of the tube bundle and flows upward through the moisture separators to the outlet

nozzle at the top of the vessel. Each Unit 1 steam generator outlet nozzle contains an integral

flow-restricting venturi that limits steam release in the event of a main steamline break (MSLB).

The steam generators include the following:

* steam generator upper and lower shells

* transition cone

* elliptical upper head

* hemispherical bottom head

* primary and secondary manways, nozzles, and safe ends

* thermal sleeves

* partition plate

* tubesheet

* U-tubes

* interior attachments

* instrumentation ports and handholes

* associated pressure-retaining bolting

The CNP steam generators were constructed in accordance with the requirements of ASME

Code, Section 1II. The Unit 1 steam generator replacement in 2000 included installation of a

new lower assembly (including tube bundle), new steam drum internals, and a new feedwater

distribution system. The steam drum internals were installed in the refurbished, original steam

drum shell. The Unit 2 steam generator replacement in 1988 included installation of a new

lower assembly (including tube bundle) and refurbishment of the upper assembly (steam drum)

and associated internals.

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Section 4.2.2.4, "Steam Generators," of the CNP UFSAR provides additional information

regarding the CNP steam generators.

In Table 2.3.1 -5 of the LRA, the applicant identified the primary-side steam generator

component types that are within the scope of license renewal and subject to an AMR, including

primary head, primary nozzles, primary nozzle safe ends, partition plates, nozzle dam retention

rings, primary manway insert plate, primary manway cover, primary manway closure bolting,

tubes/plugs, and tubesheet.

The applicant also identified the secondary-side externals, including lower shell; upper shell;

transition cone; steam drum; elliptical upper head; feedwater nozzles; feedwater nozzle thermal

sleeve (Unit 1 only); main steam nozzles; feedwater safe ends (Unit 1 only); secondary

blowdown and instrumentation connections; recirculation connections (Unit 1 only); secondary

shell drain connections (Unit 2 only); secondary handhole ports; inspection ports; secondary

handhole port covers; inspection port covers; recirculation port covers (Unit 1 only); secondary

manways; secondary manway covers; secondary manway, handhole, recirculation (Unit 1 only)

and inspection port closure bolting; steamflow restrictors (Unit 1 only); feedwater elbow thermal

liners (Unit 2 only); and feedwater liner piston rings (Unit 2 only).

Finally, the applicant identified the secondary-side internals, including tube wrappers (shroud),

tube support plates (Unit 2 only), antivibration bar (Unit 2 only), tube support plate stayrods

(Unit 2 only), tube support plate spacers (Unit 2 only), tube support plate stayrod nuts (Unit 2

only), tube support plate stayrod washers (Unit 2 only), antivibration bars retaining rings (Unit 2

only), lattice grid ring (Unit 1 only), U-bend arch bars (Unit 1 only), lattice grid ring studs (Unit 1

only), lattice grid bars (Unit 1 only), U-bend flat bars (Unit 1 only), and J-tabs (Unit 1 only) as

being within the scope of license renewal and subject to an AMR.

2.3.1.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.6 and CNP UFSAR Section 4.2.2.4 to determine whether

the applicant identified the steam generator system components within the scope of license

renewal and subject to an AMR. 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 to verify 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 within the scope of license renewal

to verify that no passive and long-lived components that should be subject to an AMR in

accordance with the requirements of 10 CFR 54.21(a)(1) were omitted.

In reviewing LRA Section 2.3.1.6, the staff identified two areas where it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, the staff issued RAls concerning these specific issues 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 following paragraphs describe the staff's RAls and the applicant's

related responses.

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RAI 2.3.1.6-1

In Table 2.3.1-5 of the LRA, the staff observed that the applicant identified the steam generator

partition plate as within the scope of license renewal and requiring aging management.

However the table does not identify one of the most significant intended functions of the

component: flow distribution. The steam generator partition plate is located in the lower head of

each steam generator and separates the hot-leg primary fluid from the cold-leg primary fluid.

Reactor coolant is located on both sides of the steam generator partition plate. The staff

understands that the intended function of the steam generator partition plates is flow distribution

(i.e., forcing the hot-leg primary flow through the steam generator tubes, thereby enabling the

steam generator to perform its primary function of heat transfer). As a result, failure of the

partition plate will degrade the heat transfer function of the steam generator. Degradation of

the heat transfer function of the steam generator has several safety consequences, including

the inability of the reactor to safely shut down and loss of natural circulation heat removal

through the steam generator which may be credited for prevention or mitigation of DBEs,

accidents, and/or NRC regulated events. In addition, the staff's position is that a partition plate

degraded by aging may develop loose parts, which may lead to flow blockage of the steam

generator tubes and thus cause degradation of the steam generator heat transfer function. In

RAI 2.3.1.6-1, the staff asked the applicant to specify flow distribution as one of the intended

functions of steam generator partition plates and to affirm the existence of an AMP that

provides reasonable assurance that the plates will not fail in a manner which can result in the

primary coolant bypassing the steam generator tubes and/or generate loose parts.

In its response dated May 20, 2004, the applicant stated that the steam generator partition plate

is a pressure boundary between the RCS inlet and outlet areas of the lower head. This partition

plate separates the primary coolant inlet chamber from the outlet chamber. Failures that

bypass the steam generator tubes and loose parts that could cause flow blockage of the steam

generator tubes would be readily apparent because of the impact on steam generator

performance during normal power operation. The applicant further stated that aging effects

associated with the component type "partition plate" listed in LRA Table 3.1.2-5 include loss of

material and cracking. The Water Chemistry Program, Alloy 600 Aging Management Program,

and Inservice Inspection Program manage these aging effects. These programs provide

reasonable assurance that the steam generator partition plate will not fail in a manner that could

result in reactor coolant bypassing the steam generator tubes or generating loose parts.

Furthermore, the applicant stated that the addition of flow distribution as an intended function

for the partition plate would have no effect on the applicant's AMR results.

Based on its review, the staff finds the applicant's response to RAI 2.3.1.6-1 acceptable,

because the applicant included the components within the scope requiring an AMR for all of its

intended functions, including the flow distribution. The applicant also identified the component

type in the LRA that includes the subject components. Therefore, the staff's concern described

in RAI 2.3.1.6-1 is resolved.

RAI 2.3.1.6-2

The staff notes that LRA Table 2.3.1-5 does not identify steam generator feedwater ring and

J-tubes as within the scope of license renewal and requiring aging management. In RAI

2.3.1.6-2, the staff asked the applicant to provide the following additional information to justify

the exclusion of subject components from the scope:

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(a) In page 19 (Chap.4) of the UFSAR, it is stated that the "J" tubes prevent

rapid drainage of the feedwater ring due to a drop in steam generator

water level and thus eliminate or reduce the possibility of water hammer

in the feedwater line. On the basis of the above statement made in the

UFSAR, it appears that the subject components are needed to prevent or

mitigate accidents; and therefore, should be in scope in accordance with

10 CFR 54.4(a)(1)(iii).

(b) Explain, if the components were relied upon to demonstrate compliance

during a design basis event, such as feedwater line break accident,

and/or Commission's regulated events.

(c) Explain, why failure of the components will not prevent in-scope

components within the steam generator (SG) from performing their

intended functions.

(d) Explain, whether the subject components are covered under any existing

inspection and/or monitoring programs, such as Steam Generator

Integrity Program.

In its response dated May 20, 2004, the applicant stated the following:

(a) The SG feedwater ring and "J" tubes are not subject to AMR because

they do not directly support the SG pressure boundary function.

Prevention of conditions that may result in water or steam hammer is

sound engineering practice exercised throughout the entire CNP plant

design. Water hammer is not a DBE; and the text in the UFSAR only

identifies a design feature of the feedwater ring and "J" tubes that may

reduce the potential for water hammer in the event of a reduction in SG

water level below the feedwatef ring.

(b) There are no DBEs or regulated events at CNP that rely upon the SG

feedwater ring or "J" tubes to demonstrate successful mitigation and

recovery from the event.

(c) As stated by the Commission in the Statement of Considerations for the

Final Part 54 Rule, "Consideration of hypothetical failures that could

result from system interdependencies that are not part of the CLB and

that have not been previously experienced is not required." CNP has not

experienced any water hammer events in the feedwater rings that led to a

line failure or DBE. Pressure boundary would be maintained in the event

of failure of the "J" tubes and feedwater ring. -

(d) The SG feedwater ring and UJf tubes are monitored as part of the SG

Monitoring Program, which implements the SG Integrity Program

described in LRA Section B.1.31. The chemistry of the feedwater and the

secondary fluid within the SG is controlled by the Primary and Secondary

Water Chemistry Control Program, which is described in LRA Section

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B. 1.40.1, to mitigate corrosion and stress corrosion cracking. No new

AMPs are required for these items.

Based on its review, the staff finds the applicant's response to RAI 2.3.1.6-2 acceptable because, as described above, the applicant explained why the component did not meet the

scoping and screening criteria outlined in 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1) and, therefore, is not required to be within the scope of license renewal. The staff's concern

described in RAI 2.3.1.6-2 is resolved.

2.3.1.5.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing basis information, and RAI responses, the staff did not identify any omissions or discrepancies in the applicant's scoping and screening results for the SCs of the steam generators. Therefore, the staff concludes that the applicant adequately identified the steam generator SCs

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant adequately identified the steam generator SCs that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.2 Engineered Safety Features

In Section 2.3.2 of the LRA, the applicant identified the SCs of the engineered safety features

(ESF) that are subject to an AMR for license renewal, including the following:

* containment spray

* containment isolation

* emergency core cooling

* containment equalization/hydrogen skimmer

2.3.2.1 Containment Spray

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 containment spray. The containment

spray system provides spray cooling water to the containment atmosphere during a loss-ofcoolant accident (LOCA) or steamline break accident inside containment. This cooling water

limits the peak pressure in the containment to below the containment design pressure. As a

secondary function, the containment spray system removes radioactive iodine from the

containment atmosphere during a LOCA.

The refueling water storage tank (RWST) is included in the containment spray system boundary. The RWST provides a source of borated water for the emergency core cooling system (ECCS) and containment spray system during the injection phase of an accident.

Sodium hydroxide solution from a single spray additive tank is mixed into both spray flow trains

to provide adequate iodine removal. Once the RWST's supply of water is exhausted, the

containment spray system takes suction from the water accumulated in the containment

recirculation sump. Additional spray ring headers, supplied by a portion of the recirculation flow

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from the residual heat removal (RHR) system, supplement the heat removal capability of the

containment spray system and are included in the review of containment spray.

The containment spray system consists of two independent, 1 00-percent capacity flow trains

with diverse power sources. Each train includes the following:

* pump

* spray additive eductor

* heat exchanger

* ring headers in both the upper and lower containment volumes, with the associated

spray nozzles, piping, valves and instrumentation necessary for operation

In support of Appendix R requirements, the RWST provides a sufficient volume of borated

water to support shutting down the unit or the opposite unit. Therefore, the containment spray

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 2.3.2-1 of the LRA, the applicant identified the containment spray component types

that are within the scope of license renewal and subject to an AMR, including bolting, eductor,

heat exchanger (shell), heat exchanger (tubes), heater housing (RWST electric heater),

manifold (piping), orifice, piping, pump casing, spray nozzle, tank, thermowell, tubing

(instrument piping), and valve.

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1 and UFSAR Sections 6.1, 6.2, and 6.3 to determine

whether the applicant identified the containment spray system components within the scope of

license renewal and subject to an AMR. 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 to verify 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 within the scope of license renewal

to verify that no passive and long-lived components that are subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1) were omitted.

The staff found that those portions of the containment spray system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal, that the

applicant identified them in LRA Section 2.3.2.1, and that Table 2.3.2-1 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.

2.3.2.1.3 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

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-L. I'

staff concludes that the applicant adequately identified the containment spray system SCs that

are within the scope of license renewal, as required by 10 CFR 54.4(a) and that the applicant

adequately identified the containment spray system SCs that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.2.2 Containment Isolation

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 isolation system.

Mechanical penetrations ensure that the primary containment can be isolated under accident

conditions to limit the release of radioactivity. For license renewal, the scope of the

containment isolation system is the passive mechanical penetration components (piping and

valves) that are not included within another AMR. In general, the applicant reviewed the

mechanical penetrations for systems with a system-level AMR with that system. Section 2.4.1

of the LRA addresses aging management for the structural elements of the mechanical

penetrations.

This grouping of the 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 purpose of license renewal." Section V.C,

"Containment Isolation Components," of the SRP-LR recognizes the grouping, stating, "The

system consists of isolation barriers in lines for BWR and PWR nonsafety systems such as the

plant heating, waste gas, plant drain, liquid waste, and cooling water systems."

The penetrations allow the passage of required fluids across the containment boundary to

support the functions of a system. The component intended function is to provide a barrier

between fission products released inside the containment and the outside environment. This is

a safety function that must also be met for the nonsafety related systems that penetrate the

containment. Therefore, the containment isolation system is within the scope of license

renewal based on the criteria of 10 CFR 54.4(a)(1).

In Table 2.3.2-2 of the LRA, the applicant identified the containment isolation component types

that are within the scope of license renewal and subject to an AMR, including bolting, piping,

and valves.

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 and UFSAR Sections 5.2.4 and 5.4 to determine

whether the applicant identified the containment isolation system components within the scope

of license renewal and subject to an AMR. 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 the review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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

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reviewed those components that the applicant identified as within the scope of license renewal

to verify that no passive and long-lived components that are subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1) were omitted.

The staff found that those portions of the containment isolation system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal, that the

applicant identified them as such in LRA Section 2.3.2.2, and that LRA Table 2.3.2-2 includes

the containment isolation 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 isolation system. Therefore, the

staff concludes that the applicant adequately identified the containment isolation system SCs

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant adequately identified the containment isolation system SCs that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.3 Emergency Core 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 ECCS. The ECCS automatically

delivers cooling water to the reactor core in the event of a LOCA. This limits the fuel clad

temperature, thereby ensuring that the core will remain substantially intact and in place with its

essential heat transfer geometry preserved. -For the rupture of a steamline or feedwater line

and the associated rapid heat removal from the core, the ECCS adds shutdown reactivity so

that there is no consequential damage to the RCS and the core remains intact and in place.

The ECCS includes the safety injection (SI) system (including the accumulators), the RHR

system, and portions of the chemical and volume control system (CVCS). The applicant

evaluated the RHR spray header components with the containment spray system in Section

2.3.2.1 of the LRA. The portions of the CVCS evaluated with the ECCS for license renewal are

the two centrifugal charging pumps and the piping and components used for safety injection.

Section 2.3.3.5 of the LRA evaluates the remainder of the CVCS.

The RHR system is also used for normal shutdown cooling. Each train of the RHR system can

remove sensible heat from the core while cooling down the plant.

The following portions of the ECCS support the requirements of 10 CFR 50.48:

* those portions of the RHR system required for removal of decay heat from the core to

achieve and maintain safe shutdown

* the centrifugal charging pumps (which provide RCS makeup)

* components that provide manual isolation capability for the accumulators following a fire

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I -

Therefore, the ECCS 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 2.3.2-3 of the LRA, the applicant identified the ECCS component types that are within

the scope of license renewal and subject to an AMR, including bolting, filter housing, flex hose,

heat exchanger (bonnet), heat exchanger (shell), heat exchanger (tubes), heater housing

(boron injection tank heater), manifold (piping), orifice, piping, pump casing, strainer housing,

tank (including accumulators), thermowell, tubing, and valve.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 and CNP UFSAR Sections 6.1 and 6.2 to determine

whether the applicant identified the ECCS components within the scope of license renewal and

subject to an AMR. The staff used the evaluation methodology described in Section 2.3 of this

SER. The staff conducted its review in accordance with the guidance in Section 2.3 of the

SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify that it 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 within the scope of license renewal to verify

that no passive and long-lived components that should be subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1) were omitted.

In reviewing LRA Section 2.3.2.3, the staff identified areas in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, the staff issued an RAI concerning the specific issues 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 following paragraphs describe the staff's RAI and the applicant's

related response.

RAI 2.3.2.3-1

The UFSAR states that screen assemblies and vortex suppressors are used in the containment

sump which provides water for the ECCS recirculation phase. One of the intended functions is

to protect the ECCS pumps from debris and cavitation caused by a harmful vortex following an

LOCA. Although LRA Table 2.4-1 lists the screens (fine and coarse) as subject to an AMR, it

does not identify the vortex suppressors and their intended function, which should also require

an AMR. In RAI 2.3.2.3-1, the staff requested that the applicant submit a clarification.

In its response dated May 20, 2004, the applicant stated that the CNP containment recirculation

sump design does not employ vortex suppressors to prevent cavitation from vortexing. The fine

and coarse screens listed in LRA Table 2.4-1 serve as flow strainers and mitigate vortex

formation by equalizing local velocity differences. The containment recirculation sump design

provides sufficient flow area over the trash curb ahead of the sump and adequate net positive

suction head for the RHR and containment spray pumps to operate in the recirculation mode.

The water level in the sump at the time of switchover from the injection phase to the

recirculation phase has been established to ensure sufficient submergence to preclude

vortexing or air entrainment. Additionally, the applicant stated that CNP analyses demonstrate

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that water inventory delivered or released to the containment from the RWST, ice melt, RCS,

and safety injection accumulators ensures that the minimum contain~ment recirculation sump

level is sufficient to preclude vortex formation in the suction flow to the ECCS and containment

spray system pumps.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.3-1 acceptable

because the applicant justified why the component does not meet the scoping and screening

criteria outlined in 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1) and as such is not required to be

within the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.2.3-1 is

resolved.

2.3.2.3.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis.information, and RAI response the staff did not identify any omissions or discrepancies in

the applicant's scoping and screening results for the components of the ECCS. Therefore, the

staff concludes that the applicant adequately identified the ECCS SCs that are within the scope

of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified

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

2.3.2.4 Containment Equalization/Hydrogen Skimmer System

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 equalization/hydrogen

skimmer (CEQ) system. The CEQ system functions postaccident, reducing pressure in the

containment and redistributing hydrogen gas from pocketed areas to the general containment

volume. These functions are the primary safety intended functions of this system. Therefore,

the CEQ system is within the scope of license renewal based on the criteria of

10 CFR 54.4(a)(1).

The system consists of two redundant independent systems that include fans, backdraft

dampers, valves, piping, and ductwork.

In Table 2.3.2-4 of the LRA, the applicant identified the CEQ component types that are within

the scope of license renewal and subject to an AMR, including bolting, damper housing,

ductwork, fan housing, heat exchanger, piping, and valve.

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 and CNP UFSAR Section 5.5 to determine whether the

applicant identified the CEQ system components within the scope of license renewal and

subject to an AMR. 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 SRP-LR,

Section 2.3.

In conducting the review, the staff reviewed the system functions described in the LRA and

UFSAR to verify 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

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reviewed those CEQ components that the applicant identified as being within the scope of

license renewal to verify 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 those portions of the CEQ system that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

applicant in LRA Section 2.3.2.4, and that the CEO system components that are subject to an

AMR in accordance with 10CFR 54.4(a) and 10 CFR 54.21(a)(1) are included in LRA Table

2.3.2-4. 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 licensingbasis information, the staff did not identify any omissions or discrepancies in the applicant's

scoping and screening results for the SCs of the CEO system. Therefore, the staff concludes

that the applicant has adequately identified the CEO system's SCs that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the CEO 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 following auxiliary system SCs that are

subject to an AMR for license renewal:

* spent fuel pool

* essential service water

* component cooling water

* compressed air

* chemical and volume control

* heating, ventilation, and air conditioning

* fire protection

* emergency diesel generator

* security

* postaccident containment hydrogen monitoring

* miscellaneous systems within scope for 10 CFR 54.4(a)(2)

* miscellaneous systems

2.3.3.1 Spent Fuel Pool

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 pool (SFP). The SFP

system maintains adequate water inventory for shielding and prevents criticality of the stored

fuel. The SFP itself (the SFP walls including the stainless steel liner, gate, and racks that

support the fuel) provides the inventory maintenance function. The applicant evaluated these

with the auxiliary building structural components in Section 2.4 of the LRA. The racks and the

neutron absorber (boral) complete the function of preventing criticality by storage rack geometry

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in the SFP and the new fuel vault. The applicant evaluated the neutron absorber as part of the

SFP system in this section of the LRA.

Section 2.3.2.2 of the LRA evaluates components providing containment isolation (fuel transfer

tube).

Section 2.3.3.6 of the LRA evaluates the portion of the SFP ventilation subject to an AMR as

the fuel handling area exhaust system.

In accordance with 10 CFR 54.4(a)(2), nonsafety related component types in the SFP systemare subject to an AMR if their failure could prevent satisfactory accomplishment of a safety

function. Nonsafety related component types that require an AMR for 10 CFR 54.4(a)(2) are in

the SFP cooling portion of the system. Section 2.3.3.11 of the LRA includes the evaluation of

SFP cooling.

As its primary safety intended function, the SFP system maintains adequate water inventory for

shielding and prevents criticality of the stored fuel. The system also provides a containment

isolation function. The system is included within the scope of license renewal because of the

potential for spatial interactions with safety related equipment. Therefore, the SFP 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)(2).

In Table 2.3.3-1 of the LRA, the applicant identified the SFP component types that are within

the scope of license renewal and subject to an AMR, including SFP poison.

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1 and CNP UFSAR Section 9.7 to determine whether

there is reasonable assurance that the applicant identified the SFP system components within

thle scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1). In LRA Section 2.3.3.11, the applicant separately compiled scoping and

screening results for all components with intended functions that were within the scope of

license renewal based on the criterion of 10 CFR 54.4(a)(2). The staff reviewed those

components for the SFP system in Section 2.3.3.11 of this SER. The staff conducted its review

in accordance with guidance of SRP-LR Section 2.3.

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 verify 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 being within the scope of license renewal to verify 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's review of LRA Section 2.3.3.1 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. Therefore,

the staff issued RAls to the applicant concerning the specific issues 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's RAls and the applicant's responses are described below. -

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RAI 2.3.3. 1-1

Section 2.3.3.1, "Spent Fuel Pool," of the LRA states, "The primary safety intended function of

the SFP system is to maintain adequate water inventory for shielding and to prevent criticality of

the stored fuel."

By letter dated February 4, 1992, which responded to a staff request for information regarding the qualification of makeup water sources, the applicant stated that makeup water to the SFP

can be obtained from several reliable, permanently installed sources. Further, the applicant stated that with these diverse sources, makeup water will be readily available in the event of

loss of SFP cooling.

In the associated SE dated January 14, 1993, the staff stated that the SFP meets the design criteria of Regulatory Guide 1.13 which requires a diversity of make up water sources to the

SFP. Previously, another SE accepted the use of the CVCS hold-up tanks as the Seismic

Category I source of make up water to the SFP.

The license renewal drawing of the SFP does not show this source of makeup water from the

CVCS hold-up tanks to the SFP or any other makeup water source as being subject to an AMR.

The staff requested that the applicant justify the exclusion of the piping and components linking the makeup water source from the CVCS hold-up tanks and at least one other makeup water

source to the SFP from being subject to an AMR in accordance with the requirements of

10 CFR 54.4(a)(1)(iii) and 10 CFR 54.21(a)(1).

In its responses, dated May 7, 2004 and September 2, 2004, the applicant stated that the

make-up water piping from the CVCS hold-up tanks to the SFP is not currently classified as

Seismic Class I. Consequently, these piping and components are not subject to an AMR in

accordance with the requirements of 10 CFR 54.4(a)(1)(iii). The applicant added that this

response is in agreement with its responses to the staff's request for additional information

pertaining to License Amendments 13, 32, 58, and 74.

In response to the staff's request for identifying a source of makeup water to the SFP within the

scope of license renewal, the applicant in its supplemental response to RAI 2.3.3.1-1 stated that

the fire water system will be credited for providing makeup water to the SFP in the event that no

other sources are available and makeup water is required.

Further, the applicant stated that the FP system is capable of delivering water to the SFP via

multiple fire hose stations in excess of the maximum calculated SFP boil-off rate should the

SFP cooling system become unavailable. The fire water hoses and associated supply piping

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

10 CFR 54.4(a)(3) and are subject to an AMR in accordance with the requirements of

10 CFR 54.21(a)(1).

However, the fire water hoses alone do not provide the diversity of makeup water sources

specified within the licensing basis of the facility. The ability to maintain adequate water

inventory in the event of a loss of SPF cooling assures that an offsite release comparable to the

10 CFR Part 100, "Reactor Site Criteria," limits would be prevented. In response to staff

inquiries regarding the qualification of makeup water sources, the applicant previously credited

the diversity of makeup water sources to assure that makeup water would be available following

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events that cause a loss of SFP cooling in lieu of identifying a makeup water source qualified as

seismic Category I. Therefore, during a subsequent telephone conference on October 27, 2004

between the NRC staff and the applicant, the staff asked that the applicant provide other

sources of makeup water in addition to the FP system that is included within the scope of

license renewal to satisfy the requirements of 10 CFR 54.4(a)(2). -

In response to the staff request for identifying a source of makeup water to the SFP other than

the fire water hoses, the applicant, in a letter dated November 18, 2004, stated that it will

additionally credit refueling water from either unit's refueling storage tank (RWST) as a second

diverse in-scope source of makeup water to the SFP. The applicant stated that the capacity of

this makeup source has been previously evaluated and determined to exceed the maximum

calculated SFP boil-off rate.

The applicant added that the additional components included in the license renewal scope are

depicted on license renewal drawing LRA-12-5136 and include those stainless steel

components (such as valves, pump, orifices, demineralizer, filters, piping, and pipe

appurtenances) in the flow path from the RWST isolation valves to the SFP. The makeup flow

path from the RWST isolation valves (1-SI-1 83 and 2-SI-1 84) includes the refueling water

purification pump and the spent fuel pit filter and terminates at the SFP. Neither the spent fuel

pit demineralizer nor the refueling water purification filter is in the makeup flow path; however,

these components are included because they provide a pressure boundary function. The

components in this flow path are included in the scope of license renewal in accordance with

the 10 CFR 54.4(a)(2) scoping criterion; however, they have not been highlighted on the license

renewal drawing.

Further, the first paragraph of LRA Section 2.3.3.11, Spent Fuel Pool Cooling, on Page 2.3-82

is modified as provided below:

The purpose of spent fuel pool cooling is to remove, from the spent fuel pool, the

heat generated by stored fuel elements. The components of the CNP spent fuel

pool cooling provide no 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) intended

functions. The maintenance of pool inventory, which assures cooling, is

provided by the spent fuel pit as discussed in Section 2.3.3.1. Those

components in the flow path from the RWST isolation valves (1 -SI-1 83 and

2-SI-1 84) to the SFP are credited as one of the diverse sources of makeup water

to the SFP, and perform a 10 CFR 54.4(a)(2) intended function. The spent fuel

pool is shared by the two units. The design incorporates two separate cooling

trains sharing a common return to the spent fuel pool. Piping is arranged so that

failure of any pipe does not drain the spent fuel pool below the top of the stored

fuel elements.

The staff finds the applicant response to RAI 2.3.3.1-1 in the September 2, 2004 and November

18, 2004 letters to be acceptable on the basis that the applicant adequately identified the non

safety related makeup water sources to the SFP system that are within the scope of license

renewal because they functionally support the SFP system's intended function. Therefore, the

staff's concerns described in RAI 2.3.3.1-1 are resolved.

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RAI 2.3.3.1-2

Section 2.1.2.1.2 of the LRA states, "licensing renewal drawings were created by marking

mechanical flow diagrams to indicate only those components within the system evaluation

boundaries that require an aging management review."

The staff requested that the applicant confirm that the system components marked on license

renewal drawings depict all the components within the SFP system that perform an intended

function (i.e., within the system evaluation boundary).

In its response dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings indicate all components that perform an intended function, with the

exception of structures, active and short-lived components, and those components that are

within the scope of license renewal and subject to an AMR based solely on the criteria of

10 CFR 54.4(a)(2). Section 2.4.2 of the LRA discusses structures depicted on license renewal

drawing LRA-12-5136 that perform an intended function. Table 2.4-2 of the LRA lists these in

the structure/component/commodity types "spent fuel pit steel (including swing gate,

attachments, liner, and fuel racks)," "spent fuel pit walls and slab," and "fuel transfer canal."

Active components that were screened out and not highlighted on flow diagrams are those that

do not meet the 10 CFR 54.21(a)(1)(i) criteria, as identified in Appendix B to NEI 95-10,

including items such as instrumentation, motors, and valve operators. License renewal drawing

LRA-12-5136 does not depict any short-lived components that perform a 10 CFR 54.4 intended

function.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.1-2 acceptable. The

applicant adequately described the process for identifying system components that are subject

to an AMR on license renewal drawings. The applicant described as necessary those

components that meet the requirements of 10 CFR 54.4(a) but are not shown on the license

renewal drawings and discussed the alteration of the system evaluation boundaries. Therefore,

the staff confirmed that the applicant evaluated all the components with intended functions for

an AMR, including those components at license renewal system boundaries and interfaces with

other systems. The applicant identified as necessary those components within the system

evaluation boundary for a license renewal system that were not subject to an AMR. Therefore,

the staff's concern described in RAI 2.3.3.1-2 is resolved.

2.3.3.1.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the SFP system. Therefore, the

staff concludes that the applicant adequately identified the SFP SCs that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the

SFP system SCs that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.2 Essential Service Water -

2.3.3.2.1 Summary of Technical Information in the Application

In Section 2.3.3.2 of the LRA, the applicant described the essential service water (ESW)

system. The ESW system supplies cooling water from the ultimate heat sink to essential heat

loads, including the following components:

* component cooling heat exchangers

* containment spray heat exchangers

* emergency diesel generators

* auxiliary feedwater pumps

* control room air conditioners (coolers and chiller condensers)

* auxiliary feedwater pump enclosure coolers

The ESW system is an emergency water supply for the emergency diesel generator (EDG)

jacket water surge tank. The Unit 1 east ESW train is cross-connected to the Unit 2 west

header, and the Unit 1 west train is cross-connected to the Unit 2 east header. In addition to its

primary intended function of providing cooling water, the ESW system is a backup suction

source for the auxiliary feedwater pumps for use when the condensate storage tank (CST) is

unavailable as a source of supply. The Appendix R safe-shutdown analysis credits the ESW

system unit cross-tie, so the system is required for compliance with the criteria of

10 CFR 50.48.

In accordance with 10 CFR 54.4(a)(2), nonsafety related portions of the system are subject to

an AMR if their failure could prevent satisfactory accomplishment of a safety function. -

Nonsafety related component types in the ESW system that require an AMR pursuant to

10 CFR 54.4(a)(2) are in the auxiliary building and screenhouse and consist of bolting, valves,

tubing, and piping. The environment and materials are the same in safety related and

nonsafety related portions of the system. The AMR results in Table 3.3.2-2 of the LRA apply to

the portions of the system requiring an AMR pursuant to 10 CFR 54.4(a)(2).

The ESW system is the safety related source of cooling to ESF equipment. The ESW system

also provides cooling to Appendix R safe-shutdown equipment. Nonsafety related portions ofthe system must maintain mechanical and structural integrity so that nearby safety related

equipment is not adversely affected. Consequently, the 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 2.3.3-2 of the LRA, the applicant identified the ESW component types that are within

the scope of license renewal and subject toan AMR, including bolting, detector well, expansion

joint, fittings, flex hose, manifold (piping), orifice, piping, pump casing, strainer, strainer

housing, thermowell, tubing, and valve.

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 and CNP UFSAR Section 9.8.3 to determine whether

there is reasonable assurance that the applicant identified the ESW system components within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

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. I

10 CFR 54.21 (a)(1). The staff used the evaluation methodology described in Section 2.3 of this

SER. The staff conducted its review in accordance with Section 2.3 guidance of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 being within the scope of license

renewal to verify 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's review of LRA Section 2.3.3.2 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. Therefore,

the staff issued RAIs to the applicant concerning these specific issues 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's RAls and the applicant's responses are described below.

RAI 2.3.3.2-1

Table 2.3.3-2 of the LRA lists tubing in the ESW as subject to an AMR. However, the ESW

license renewal drawings do not identify tubing. The staff asked the applicant to identify the

ESW tubing that is within the scope of license renewal and subject to an AMR.

In its response dated May 7, 2004, the applicant stated that instruments typically include tubing

from the process piping to the instrument, although the LRA drawings do not always show this

tubing. The license renewal drawings highlight entire instrument lines between the main

process piping up to the instrument indicating that they are subject to an AMR. Instrument lines

typically include tubing as a part of the routing to the instrument, even though it is not

specifically identified as tubing on the drawing. In LRA Table 2.3.3-2, the "tubing" entry

represents instrument tubing, and the "piping" entry represents process and/or instrument

piping. The table lists both component types to describe the complete passive mechanical

pressure boundary up to the instruments. Table 3.3.2-2 of the LRA provides the AMR results

for the tubing.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-1 acceptable

because the applicant identified and evaluated ESW tubing in the LRA. Therefore, the staff's

concern described in RAI 2.3.3.2-1 is resolved.

RAI 2.3.3.2-2

License renewal drawings of the ESW system identify "auto vent auxiliary building ventilation

system" components shown at various locations to be within the scope of license renewal and

subject to an AMR. However, this component group is not listed in Table 2.3.3-2 as being

subject to an AMR. The applicant was asked to include the Auto Vent VA component group in

Table 2.3.3-2 or justify the exclusion of this group from the table.

In its response dated May 7, 2004, the applicant stated that it included the auto vent VA

components under the component type "valve" and included them in the AMR of the ESW

system.

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Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-2 acceptable

because Table 2.3.3-2 of the LRA represents the auto vent VA components and they are

evaluated for an AMR. Therefore, the staff's concern described in RAI 2.3.3.2-2 is resolved.

RAI 2.3.3.2-3

Section 2.3.3.2 of the LRA states that the license renewal drawings do not indicate components

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

10 CFR 54.4(a)(2). This section also states, "nonsafety-related component types in the ESW

system that require an AMR for 10 CFR 54.4(a)(2) are in the auxiliary building and screenhouse

and consist of bolting, valves, tubing and piping."

The staff asked the applicant to clarify whether all the bolting, valves, tubing, and piping in the

auxiliary building and screenhouse are within scope and subject to an AMR in accordance with

10 CFR 54.4(a)(2) and 10 CFR 54.21 (a)(1). If not, the staff asked the applicant to identify the

components that are within scope and subject to an AMR.

The 10 CFR 54.4(a)(2) identification process, as described in the applicant's response to RAI

2.3.3.11-2, designates nonsafety-related systems and components with the potential for spray

or leakage that could prevent safety-related systems and components from performing their

required safety function. Conservatively, the applicant determined all nonsafety-related

components containing liquid or steam located in the auxiliary building and screenhouse to be

subject to an AMR unless no safety-related equipment is in the area.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-3 acceptable

because the applicant's responses to RAI 2.3.3.11-2 adequately described the components in

the auxiliary building and screenhouse that are subject to an AMR in accordance with

10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.3.2-3 is resolved.

RAI 2.3.3.2-4

Section 2.1.2.1.2 of the LRA states, "licensing renewal drawings were created by marking

mechanical flow diagrams to indicate only those components within the system evaluation

boundaries that require an aging management review."

The staff requested that the applicant confirm that the system components marked on the

license renewal drawing depict all the components within the ESW system that perform an

intended function (i.e., within the system evaluation boundary).

In its response dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings include all components that perform an intended function, with the

exception of structures, active and short-lived components, and those components that are

within the scope of license renewal and subject to an AMR based solely on the criteria of

10 CFR 54.4(a)(2). Active components that were screened out and not highlighted on flow

diagrams are those that do not meet the 10 CFR 54.21 (a)(1)(i) criteria, as identified in

Appendix B to NEI 95-10, including items such as instrumentation, motors, and valve operators.

The license renewal drawings do not include any short-lived components that perform a

10 CFR 54.4 intended function.

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Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-4 acceptable. The

applicant adequately described the process for identifying system components on license

renewal drawings that are subject to an AMR. The applicant described as necessary the

components that meet the requirements of 10 CFR 54.4(a) but are not shown on the license

renewal drawings and discussed the alteration of the system evaluation boundaries. Therefore, the staff confirmed that the applicant evaluated all the components with intended functions for

an AMR, including those components at license renewal system boundaries and interfaces with

other systems. The applicant identified as necessary those components within the system evaluation boundary for a license renewal system that are not subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.2-4 is resolved.

2.3.3.2.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing basis information, and RAI responses, the staff did not identify any omissions or discrepancies in the applicant's scoping and screening results for the SCs of the ESW system. Therefore, the staff concludes that the applicant adequately identified the ESW SCs that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the ESW system SCs that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.3 Component Cooling Water

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 CCW system. The CCW system provides cooling to potentially radioactive heat sources and ensures that leakage of radioactive

fluid from those heat sources is contained within the plant. The CCW system is an

intermediate, closed-loop system between heat sources and the ultimate heat sink (Lake Michigan). Components cooled by the CCW system are split between two redundant

safeguards trains and a miscellaneous service train that may be supported by either safeguards train. The CCW system removes heat from the RCS, the SFP, and various plant heat

exchangers and components. The CCW system then transfers that heat to the ESW system.

In accordance with 10 CFR 54.4(a)(2), nonsafety related component types in the CCW system

are subject to an AMR if their failure could prevent satisfactory accomplishment of a safety function. Nonsafety related component types that require an AMR for 10 CFR 54.4(a)(2) are in

the auxiliary building and consist of the following:

* bolting

* tanks

* eductors

* valves

* manifolds

* tubing

* piping

The applicant addressed nonsafety related heat exchangers supplied with CCW as required with the systems they cool. The environment and materials are the same in safety related and

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nonsafety related portions of the system. The AMR results in Table 3.3.2-3 of the LRA apply to

the portions of the CCW system requiring an AMR for 10 CFR 54.4(a)(2).

The CCW system is the safety related source of cooling to ESF equipment. The CCW system

also provides cooling to Appendix R safe-shutdown equipment. Portions of the system without

a safety function must maintain mechanical and structural integrity so that nearby safety related

equipment is not adversely affected. Consequently, the CCW 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 LRA Table 2.3.3-3, the applicant identified the CCW component types that are within the

scope of license renewal and subject to an AMR, including bolting, detector well, expansion

joint, fittings, heat exchanger, heat exchanger (bonnet), heat exchanger(shell), heat exchanger

(tubes), manifold (piping), orifice, piping, pump casing, strainer - tee, tank, thermowell, tubing,

and valve.

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3 and CNP UFSAR Section 9.5 to determine whether

there is reasonable assurance that the applicant identified the CCW system components within

the scope of license renewal and subject to an AMR, in accordance with the requirements of

10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff used the evaluation methodology described in

Section 2.3 of this SER. The staff conducted its review in accordance with the guidance in

Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 being within the scope of license

renewal to verify 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's review of the LRA Section 2.3.3.3 identified areas in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, the staff issued RAls to the applicant concerning these specific issues to determine

whether the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21 (a)(1)

were properly applied. The following describes the staff's RAls and the applicant's responses.

RAI 2.3.3.3-1

The following items are shown on the license renewal drawings as within the scope of license

renewal and subject to an AMR. However they are not listed in Table 2.3.3-3, "Component

Cooling Water (CCW) System Components Subject to Aging management Review." The staff

requested that the applicant explain why these components are not listed in Table 2.3.3-3 as

components subject to an AMR.

(a) Upper and lower bearing oil coolers shown on the license renewal drawings

LRA-1 -5135D and LRA-2-5135D

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(b) External pipe coils shown on the license renewal drawings LRA-1 -51 35E and

LRA-2-51 35E

In its response dated May 7, 2004, the applicant stated the following:

(a) Upper bearing oil coolers are included in LRA Table 2.3.3-3 under the

component types "Heat exchanger (shell)" and "Heat exchanger (tubes)."

Lower bearing oil coolers are included in LRA Table 2.3.3-3 under the

component type, uHeat exchanger."

(b) External pipe coils are included in LRA Table 2.3.3-3 under the

component type, "Heat exchanger."

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-1 acceptable,

because the bearing oil coolers and pipe coils are represented on Table 2.3.3-3 and are

evaluated for an AMR as indicated in Table 3.3.2-3. Therefore, the staff's concern described in

RAI 2.3.3.3-1 is resolved.

RAI 2.3.3.3-2

LRA Table 2.3.3-3 lists tubing, strainer-tee, and expansion joint as component groups that are

subject to an AMR. However, the staff is not able to identify them on the license renewal

drawings as components subject to an AMR. The staff requested the applicant to identify CCW

system tubing, stainer-tees, and expansion joints that are subject to an AMR and provide

justification for those that are not subject to an AMR.

In its response dated May 7, 2004, the applicant stated that the CCW system instrument tubing

is subject to an AMR based on the criteria of 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(3). The

instrument tubing is highlighted on license renewal drawings by highlighting the entire line up to

each instrument, including the tubing between the process piping and the instrument.

Component types 'tubing" and "piping" represent the tubing. The LRA table also represents

nonsafety-related CCW system instrument tubing subject to an AMR based solely on the

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

Additionally, CCW strainer-tees subject to an AMR are highlighted on the drawings. Since they

have specific component numbers on the drawings, they were specified as components subject

to an AMR.

CCW expansion joints subject to an AMR are highlighted on the drawings. Since they have

specific component numbers on the drawings, they were specified as components subject to an

AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-2 acceptable

because the components in question have been adequately identified and represented in the

LRA tables and are evaluated for an AMR. Therefore, the staff's concern described in RAI

2.3.3.3-2 is resolved.

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RAI 2.3.3.3-3

Section 2.3.3.3 of the LRA lists eductors as nonsafety-related components in the auxiliary

building that require an AMR in accordance with 10 CFR 54.4(a)(2). However, the license

renewal drawing for the CCW system does not show eductors, nor does LRA Table 2.3.3-3 list

them as components subject to an AMR. The staff requested the applicant identify the

eductors in the CCW system and explain why LRA Table 2.3.3-3 does not list them as

components subject to an AMR.

In its response, dated May 7, 2004, the applicant stated that the CCW chemical mixing tank

eductor shown on drawing LRA-1 -5135 requires AMR for 10 CFR 54.4(a)(2) only. LRA Section

2.1.2.1.2 states that components that are within the scope of license renewal based solely on

the criterion of 10 CFR 54.4(a)(2) are not indicated on LRA drawings. LRA Table 2.3.3-3 only

includes components that are subject to an AMR for 10 CFR 54.4 (a)(1) or 10 CFR 54.4 (a)(3).

LRA Section 2.3.3.11 describes the CCW system as a Group I system (i.e., the material and

environments are the same in the portion of the system meeting the criteria of

10 CFR 54.4(a)(2) as for those portions meeting the criteria of 10 CFR 54.4(a)(1) or

10 CFR 54.4(a)(3)). Therefore, AMPs for the environmental and material combinations

identified in LRA Table 3.3.2-3 will manage aging for the eductor.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-3 acceptable

because it stated that eductors in the CCW system are subject to an AMR. In addition, the AMP

identified in LRA Table 3.3.2-3 will manage the aging effects for the CCW eductors. Therefore,

the staff's concern described in RAI 2.3.3.3-3 is resolved.

RAI 2.3.3.3-4

License renewal drawings show portions of the CCW system piping between the license

renewal boundary flags leading to and from the seal water heat exchangers and to and from the

letdown heat exchangers, including the heat exchangers tubes and shells, as not subject to an

AMR. However, parts of the seal water heat exchanger and letdown heat exchangers (heat

exchanger channel, tubesheet, and tube side nozzles) that are within the CVCS license renewal

boundary are shown as subject to an AMR. -The staff requested the applicant to explain why it

excluded these portions of the CCW system from an AMR in accordance with the requirements

of 10 CFR 54.21(a)(1).

In its response dated May 7, 2004, the applicant stated that the CVCS seal water and letdown

heat exchangers contain reactor coolant on the tube side and CCW on the shell side. One

CVCS intended function is to maintain the system pressure boundary to contain reactor coolant

fluid. Consequently, the tube side of these heat exchangers requires aging management. Heat

transfer is not a 10 CFR 54.21 (a)(1) intended function for these heat exchangers.

Consequently, CCW supply to the seal water and letdown heat exchangers is not required,

based on the criteria of 10 CFR 54.21 (a)(1). In the response to RAI 2.3.3.3-5, the applicant

provided additional discussions that support the basis for the CCW system scope boundaries

with regard to CCW inventory loss.

In conclusion, the seal water and letdown heat exchangers are required for the CVCS pressure

boundary intended function only. The CCW side of the heat exchangers does not perform a

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10 CFR 54.21 (a)(1) intended function and consequently is not marked on the license renewal

drawings.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-4 acceptable, because it explained that the CCW side of the seal water and letdown heat exchangers does

not have a pressure boundary intended function, thus it is excluded from being subject to an

AMR in accordance with the requirement of 10 CFR 54.21 (a)(1). Therefore, the staff's concern

described in RAI 2.3.3.3-4 is resolved.

RAI 2.3.3.3-5

The boundary of the portion of the CCW system that is subject to an AMR ends at valves that

are shown on the license renewal drawings as normally open. Failure of the downstream piping

may affect the pressure boundary intended function. However, Section 2.3.3.3 of the LRA does

not discuss why this approach is acceptable. The staff asked the applicant to provide additional

information to support the basis for this determination. For example, the staff asked the

applicant to discuss the steps in the procedures for identifying the locations of breaks and

closing the valves, the amount of time required to complete these steps, and the consequences

on system inventory if the valves are not closed.

In its response dated May 7, 2004, the applicant stated that the CCW system is an intermediate

closed-loop system between heat sources and the ultimate heat sink. The applicant further

described the functions of the CCW system as meeting the criteria of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3).

The applicant stated that the normally open valves in question are associated with the CCW

miscellaneous services header and that this is acceptable based on safety significance, system functional requirements, and postulated failure modes. The applicant provided an evaluation of

the affected loads on this header, along with the effects of the header's loss of inventory and its

ability to perform system intended functions.

Additionally, the applicant described the CCW system monitoring instrumentation for loss of

inventory. It described the actions to diagnose and mitigate the loss of inventory, based on

approved procedures. The applicant concluded that motor-operated main header isolation

valves provide the primary isolation boundaries for the CCW system miscellaneous services

header, and for a leak in a nonsafety-related branch load, the main header isolation valves

would be closed from the control room to isolate the leak minutes after alarm receipt and

subsequent diagnosis of the failure.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-5 acceptable because the applicant's explanations for selecting the system boundaries are appropriate with

respect to the scoping methodology. Therefore, the staff's concerns described in RAI 2.3.3.3-5

are resolved.

RAI 2.3.3.3-6

Section 2.1.2.1.2 of the LRA states, "licensing renewal drawings were created by marking mechanical flow diagrams to indicate only those components within the system evaluation

boundaries that require an aging management review."

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The staff requested that the applicant confirm that system components marked on the CCW

license renewal drawings depict fil the mechanical components that perform an intended

function within the CCW system evaluation boundary.

In its response dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings indicate all components that perform an intended function, with the

exception of structures, active and short-lived components, and those components that are -

within the scope of license renewal and subject to an AMR based solely on the criteria of

10 CFR 54.4(a)(2). The AMRs for the structural elements of the CCW containment

penetrations, shown on license renewal drawings, are grouped with the structural review in LRA

2.4.1. The CCW system includes components with a potential for 10 CFR 54.4(a)(2) functional

failure, as well as spatial interaction.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-6 acceptable.' The -

applicant adequately described the process for identifying system components that are subject

to an AMR on license renewal drawings. The applicant described as necessary the - -

components that meet the requirements of 10 CFR 54.4(a) but are not shown on the license

renewal drawings and discussed the alteration of the system evaluation boundaries. Therefore,

the staff confirmed that it evaluated all the components with intended functions for an AMR,

including those components at license renewal system boundaries and interfaces with other

systems. The applicant identified as necessary those components within the system evaluationboundary for a license renewal system that are not subject to an AMR. Therefore, the staff's

concern described in RAI 2.3.3.3-6 is resolved.

RAI 2.3.3.3-7

Section 2.1.2.1.2 of the LRA states that the applicant created license renewal drawings by

marking mechanical flow diagrams to indicate only those components within the system

evaluation boundaries that require an AMR. Components that are within the scope of license

renewal based solely on the criteria of 10 CFR 54.4(a)(2) are not generally indicated on the

drawings but are described in Section 2.3 and listed in Table 3.3.2-11 of the LRA.

Pursuant to 10 CFR 54.21 (a)(1), the applicant must identify and list those SCs subject to an

AMR. The staff's position is that the applicant did not satisfy this requirement because the

components of the CCW system meeting 10 CFR 54.4(a)(2) are neither listed nor identified on

drawings. The applicant included these components as "component types," instead of as

individually listed components. The staff requested that the applicant confirm that the CCW

system components marked on license renewal drawings depict all the components within the

CCW system that meet the requirements of 10 CFR 54.4(a)(2). If not, the staff requested the

applicant to provide a list of these components that are not marked on license renewal drawings

or provided revised drawings as needed to include the additional components.

In its response dated May 20, 2004, the applicant stated that, since the potential for a

10 CFR 54.4(a)(2) functional failure concern exists, clarification-of the license renewal drawings

for the CCW miscellaneous services header components that are within the scope of licenserenewal and subject to an AMR is warranted. The applicant adequately identified those

portions of the CCW miscellaneous services header that meet the 10 CFR 54.4(a)(2)

criterionon drawings and in tables.

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In its response to RAI 2.3.3.11-2, dated May 7, 2004 and September 2, 2004, the applicant discussed the scoping and screening of components meeting the 10 CFR 54.4(a)(2) criterion.

These components include nonsafety-related components containing liquid or steam located in

the containment building, auxiliary building, screenhouse, and the portion of the turbine building that contains the auxiliary feedwater pumps unless no safety related equipment is in the area.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-7 acceptable

because the applicant adequately addressed questions concerning the scoping and screening of components meeting the requirements of 10 CFR 54.4(a)(2) for the CCW system. Therefore, the staff's concerns described in RAI 2.3.3.3-7 are resolved.

2.3.3.3.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing basis information, and RAI responses, the staff did not identify any omissions or discrepancies in the applicant's scoping and screening results for the SCs of the CCW system. Therefore, the

staff concludes that the applicant adequately identified the CCW SCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified

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

2.3.3.4 Compressed Air

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 compressed air (CA) system. This

section covers the components in the CA system, which includes both the control air (CTRLA) and plant air (PA) systems. This section also includes the reactor nitrogen (N2) system, since

portions of the N2 system provide a backup supply to the CA system.

Control Air. The CTRLA system provides a continuous supply of dry, oil-free, filtered

compressed air to pneumatic instruments and air-operated valves and dampers for various

process systems. Compressed CTRLA is supplied to components in the turbine building, auxiliary building, and containment. Major components of the CTRLA system include the

following:

* control air compressors

* wet control air receivers

* prefilters

* air dryers

* afterfilters

* dry control air receivers

* associated distribution piping and valves

The CTRLA system is part of the CA system described in the UFSAR. The CTRLA system has

a safety intended function of providing the CTRLA required to support the operation of 6 limited

number of safety related components. It also has a containment isolation function. Control air

is supplied to components required to operate for the Appendix R safe-shutdown analysis and

for the SBO event. Therefore, this 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).

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Plant Air. The PA system provides CA throughout the plant for service usage and ice

condenser outage support. CA is supplied to CNP, Units 1 and 2, through an air distribution

system located in the turbine building, auxiliary building, containment, and screenhouse

building. This distribution system consists of a shared PA ring header extending throughout the

turbine building, a pair of parallel PA headers in the auxiliary building, and a PA header in each

containment. One PA compressor, PA receiver, and PA aftercooler is located in each unit. The

PA system is part of the CA system described in the UFSAR.

Because some components of the PA system are associated with containment isolation, the PA

system is within the scope of license renewal based on 10 CFR 54.4(a)(1). The system

provides no other function that meets the scoping criteria for license renewal.

Reactor Nitrogen. The N2 system provides nitrogen for purging and blanketing tanks and

equipment in the RCS and nuclear auxiliary systems for both Units 1 and 2. The N2 system

also supplies nitrogen to the ECCS accumulators and to the steam generator power-operated

relief valves (backup supply).

The backup nitrogen supply to the steam generator power-operated relief valves supports

operation of these valves for a controlled cooldown for the Appendix R safe-shutdown analysis.

Therefore, the system is within the scope of license renewal based on the criteria of

10 CFR 54.4(a)(3).

Because some components of the N2 system are associated with containment isolation, the N2

system is within the scope of license renewal based on 10 CFR 54.4(a)(1). Section 2.3.2.2 of

the LRA evaluates the containment isolation components for the N2 system. Section 2.3.2.3 of

the LRA evaluates the nitrogen supply to the ECCS accumulators.

In Table 2.3.3-4 of the LRA, the applicant identified the CA component types that are within the

scope of license renewal and subject to an AMR, including bolting, fittings, flex hose, piping,

tank, tubing, and valve.

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 and CNP UFSAR Section 9.8.2 to determine whether

there is reasonable assurance that the applicant identified the CA system components within

the scope of license renewal and subject to an AMRI in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1). The staff conducted its review in accordance with the guidance in Section

2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 being within the scope of license

renewal to verify 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's review of the LRA Section 2.3.3.4 identified areas in which additional information

was necessary to complete the review of the applicant's scoping and screening results.

Therefore, the staff issued RAls to the applicant concerning these specific issues to determine

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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's RAls and the applicant's responses are described

below.

RAI 2.3.3.4-1

The staff asked the applicant to clarify whether the components listed in Table 2.3.3-4 are

subject to an AMR. If not, in RAI 2.3.3.4-1, summarized below, the staff asked the applicant to

justify the exclusion of these components from an AMR in accordance with the requirements of

10 CFR 54.21 (a)(1):

(a) License renewal drawings show pressure regulators within the scope of license renewal

and subject to an AMR: LRA-1-5120R, and LRA-2-5120R and LRA-1-5120S and

LRA-2-5120S. However, housings of these regulators, which are passive and

long-lived, are not specifically listed as components subject to an AMR in Table 2.3.3-4.

(b) License renewal drawings LRA-1-5120R, LRA-2-5120R, LRA-1-5120S, and

LRA-2-5120S show components MRV-223-VB1, MRV-223-VB2, MRV-233-VB1,

MRV-233-VB2, MRV-213-VB1, MRV-213-VB2, MRV-243-VB1, and MRV-243-VB2 as

within the scope of license renewal and subject to an AMR. Also, the applicant was

asked to identify these components because they are not identified either on the

standard symbol drawings or the control air system standard symbol drawing.

(c) License renewal drawing LRA-12-51 1 8B shows an electronic pneumatic transducer

within the scope of license renewal and subject to an AMR. However, the pressure

retaining boundary of this component, which is passive and long-lived, is not specifically

listed as a component subject to an AMR in Table 2.3.3-4.

In its response dated May 7, 2004, the applicant stated the following:

(a) Pressure retaining portions of pressure regulators (or pressure control

valves) shown as subject to an AMR on drawings LRA-1-5120R,

LRA-2-5120R. LRA-1-5120S and LRA-2-5120S are included in

component type 'valve" listed in LRA Table 2.3.3-4.

(b) Components, N4RV-233-VBI. MRV-223-VB2, MRV-233-VBI,

MRV-233-VB2, MRV-213-VB1, MRV-213-VB2, MRV-243-VBI, and

MRV-243-VB2 are steam generator power operated relief valve (PORV)

upper and lower pneumatic volume boosters used for manual local

operation of the steam generator PORVs. Pressure retaining portions of

these components are included in component type "valve" listed in LRA

Table 2.3.3-4.

(c) Pressure retaining portions of electronic pneumatic transducers

2-GRV-354 on drawing LRA-1 2-5118B, and 1 -GRV-354 are included in

component type "Valve" listed in LRA Table 2.3.3-4.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-1 acceptable

because it adequately explains that the pressure retaining portions of the pressure regulators,

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power operated relief valves, and electronic pneumatic transduces are included in the

component type "valve" which is listed in Table 2.3.3-4 as a component type subject to an AMR.

Therefore, the staff's concerns described in RAI 2.3.3.4-1 are resolved.

RAI 2.3.3.4-2

On license renewal drawings LRA-1 -5120R, LRA-2-5120R, LRA-1 -5120S, and LRA -2-5120S,

components marked as MRV-223, MRV-233, MRV-213, and MRV-243 are shown as excluded

from requiring an AMR. However, it appears that these components have pressure boundary

intended function. These components are not identified either on the standard symbol drawings

or control air system standard symbol drawing. The applicant was asked to identify these :

components and clarify whether they are passive and long-lived. If so, the applicant was asked

to explain why these components are not shown on the drawings and listed in LRA Table

2.3.3-4 as being subject to an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1).

In its response dated May 7, 2004, the applicant stated that components MRV-223, MRV-233,

MRV-213, and MRV-243 are the steam generator power-operated relief valves (PORVs). The

applicant reviewed the valves in the main steam system, showed them on drawings -

LRA-1-5105D and LRA-2-5105D as subject to an AMR, and included them in the component

type "Valve" listing in LRA Table 2.3.4-2. However, the operators for these valves shown on

drawings LRA-1-5120R, LRA-2-5120R, LRA-1-51 20S, and LRA-2-51 20S are active components

and are therefore not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-2 acceptable,

because it adequately explains that PORVs are subject to an AMR and are included in the

"valve" component type listed in LRA Table 2.3.4-2. Furthermore, the applicant justified

exclusion of the valve operators from being subject to an AMR as active components.

Therefore, the staff's concerns described in RAI 2.3.3.4-2 are resolved.

RAI 2.3.3.4-3

Section 2.1.2.1.1 of the LRA states that the identification of components subject to an AMR

begins with the determination of the system evaluation boundary. The system evaluation

boundary includes those portions of the system that are necessary to ensure that the intended

functions of the system will be performed. Components needed to support each of the systemlevel intended functions identified in the scoping process are included within the system

evaluation boundary.

The staff could not verify whether the applicant identified all the components that perform an

intended function because the applicant did not identify the components within the system

evaluation boundary in its LRA. The staff must verify this information to effectively review the

LRA using the SRP-LR.

The staff requested that the applicant confirm that the system components marked on license

renewal drawings for the CA system depict all the components that perform an intended

function. If not, the staff asked the applicant to provide a list of those components that perform

an intended function but are not marked on license renewal drawings, or provide revised

drawings as needed to include the additional components.

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In its response, dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings indicate all components that perform an intended function with the

exception of structures, active and short-lived components, and those components that are in

scope and subject to an AMR based solely on the criterion of 10 CFR 54.4(a)(2). Active

components that were screened out, and are therefore not highlighted on flow diagrams, are

those that do not meet the 10 CFR 54.21 (a)(1)(i) criteria, as identified in Appendix B to NEI 95-

10. This includes items such as instrumentation, motors and valve operators.

In the CA system, a number of relief valves on non-safety related piping are identified as safety related on license renewal drawings. These relief valves perform the active function of

providing overpressure protection of fail-safe, air-operated valves in the event of a regulator failure. The pressure boundary function is not required to be maintained for these components because they are not in a safety related containment isolation boundary or in a portion of the

system with a required backup accumulator. Therefore, an AMR is not required for these relief

valves.

Mechanical components in the back-up CA supply to the pressurizer power-operated relief

valves are highlighted on license renewal drawings LRA-1 -5120D and LRA-2-5120D. The

reserve control air tanks are subject to an AMR. However, the air bottles are frequently replaced with new bottles; therefore, these air bottles are not long-lived components, and they do not require an AMR.

Further, the mechanical components in the back-up air supply for the post-accident containment hydrogen monitoring system (PACHMS) are shown on license renewal drawings LRA-1-5120NN and LRA-2-5120KK. The back-up air tanks are frequently replaced with new

tanks; therefore these tanks are not long-lived components, and they are not subject to an

AMR.

Based on the operating experience, the nonsafety related air components do not pose a hazard

to other plant equipment, and cannot adversely affect safety related components due to

leakage or spray. As a result nonsafety related components in the CA system that contain dry air or gas do not meet the 10 CFR 54.4(a)(2) criterion, and are not in the scope of license

renewal.

The CA system license renewal drawings do not depict any short-lived components that

perform a 10 CFR 54.4 intended function.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-3 acceptable because it adequately justifies the exclusion of the CA system nonsafety related components from the scope of license renewal and an AMR in accordance with the requirements of

10 CFR 54.4 (a)(2) and 10 CFR 54.21 (a)(1), respectively. Therefore, the staff's concerns

described in RAI 2.3.3.4-3 are resolved.

2.3.3.4.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing basis information, and RAI responses, the staff did not identify any omissions or discrepancies in the applicant's scoping and screening results for the SCs of the CA system. Therefore, the

staff concludes that the applicant adequately identified the CA SSCs that are within the scope

I

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of license renewal, as required by. 0 CFR 54.4(a), and that the applicant adequately identified

the CA system SCs that are subject to an AMR, as required by 1 0 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

The applicant described the CVCS in Section 2.3.3.5 of the LRA. The CVCS supports the RCS

in a variety of ways and has the following functions:

* adjust the concentration of boric acid

* maintain the proper water inventory in the RCS

* provide the required seal water flow for the RCP shaft seals

* process reactor coolant effluent for reuse of boric acid and reactor makeup water

* maintain the proper concentration of corrosion-inhibiting chemicals in the reactor coolant

* maintain the reactor coolant activities within design limits

* provide borated water for safety injection

* fill and hydrostatically test the RCS

The centrifugal charging pumps and piping and components used for Si are evaluated as part

of the ECCS, which is described in Section 2.3.2.3 of the LRA. Class 1 piping and associated

pressure boundary components in the reactor coolant pressure boundary are evaluated with the

RCS, which is described in Section 2.3.1.4 of the LRA.

The CVCS intended functions include the following:

* maintaining the RCS pressure boundary

* providing RCS inventory control

* providing borated water for reactivity control

* supporting ECCS injection

* providing RCP seal injection and processing seal leakoff

* providing cross-unit charging to support Appendix R-required safe shutdown of the

opposite unit, which includes RCP seal injection, RCS inventory makeup, and reactivity

control

In accordance with 10 CFR 54.4(a)(2), nonsafety related portions of the system are subject to

an AMR if their failure could prevent satisfactory accomplishment of a safety function. Certain

nonsafety related component types in the CVCS, including those components that provide RCP

seal injection and seal leakoff processing, meet the criteria of 10 CFR 54.4(a)(2). These

components are in the auxiliary building and containment. The environment and 'materials of

the components are the same in both the safety related aand nonsafety related portions of the

system. The AMR results in Table 3.3.2-5 of the LRA apply to the portions of the system

requiring an AMR, in accordance with 10 CFR 54.4(a)(2).

The Appendix R safe-shutdown analysis credits the CVCS (including the pump discharge crosstie) for RCP seal injection, RCS inventory makeup, and reactivity control. The applicant

credited CVCS components with minimizing the" loss of RCP seal water during an SBO event.

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The CVCS is within scope as a safety related system, and portions are within scope as

nonsafety related affecting safety related components. Portions of the CVCS are required to

support FP requirements and requirements for SBO. Therefore, the CVCS 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 2.3.3-5 of the LRA, the applicant identified the CVCS component types that are within

the scope of license renewal and subject to an AMR, including bolting, filter housing, flow

element body, heat exchanger (bonnet), heat exchanger (shell), heat exchanger (tubes), heater

housing, level glass gauge, manifold (piping), orifice, piping, piping-spool assembly, pulsation dampener, pump casing, strainer - tee, tank, thermowell, tubing, and valve.

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5 and CNP UFSAR Section 9.2 using the evaluation

methodology described in Section 2.3 of this SER and in accordance with 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 verify 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 within the scope of license renewal to verify 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 identified those portions of the

CVCS that meet the scoping requirements of 10 CFR 54.4(a) and included them within the

scope of license renewal in LRA Section 2.3.3.5. The applicant also included the CVCS

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 2.3.3-5. 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 scoping and screening results for the SCs of the CVCS. Therefore, the staff

concludes that the applicant adequately identified the CVCS SCs that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the

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

2.3.3.6 Heating, Ventilation, and Air Conditioning

2.3.3.6.1 Summary of Technical Information in the Application

This section covers the heating, ventilation, and air conditioning (HVAC) subsystems and

components within the scope of license renewal for CNP, with two exceptions. The exceptions include the CEQ system, which is an engineered safeguards system covered in Section 2.3.2 of

this SER, and the auxiliary building ventilation and miscellaneous ventilation systems, which are

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only within scope based on the criteria of 10 CFR 54.4(a)(2) and are discussed in Section

2.3.3.11 of this SER.

Engineered Safety Features Ventilation. The engineered safety features (ESF) ventilation

system maintains temperatures in the portions of the building housing ESF equipment within

design limits for operation of equipment and for personnel access for inspection, maintenance,

and testing, as required. The enclosures for ESF equipment are in the lower three ldvels'of the

auxiliary building and are ventilated by two separate ventilation systems.

The areas serviced by the ESF ventilation system include the following:

* -containment spray pump enclosures

* -RHR pump enclosures

* 'safety injection pump enclosures

* RHR heat exchanger enclosures

* containment spray heat exchanger enclosures

* reciprocating and centrifugal charging pump enclosures

For the purposes of license renewal, the ventilation subsystems servicing the following areas

are reviewed with the ESF ventilation system:

cow pump rooms

* AFW pump rooms

* ESW pump rooms

* FP pump house

The safety intended functions of this system are to maintain a suitable operating environment

for equipment located in the serviced areas and to remove iodine and particulates from ECCS

leakage following an accident. The'system also supports the Appendix R safe-shutdown'

analysis by providing cooling to the safe-shutdown equipment of the opposite unit. Therefore,

the ESF 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).-

Control Room Ventilation. The control room ventilation system maintains control room

temperature and humidity and provides a fresh air supply to the control room during normal

operation and accident conditions. One of two full-capacity air handling units supplies

conditioned air to the control room envelope. The air conditioning system normally provides

continuous pressurization of the control room envelope to prevent entry of dust and dirt. A

separate air-handler with roughing filters, high efficiency particulate air filters, and charcoal

adsorbers provides emergency filtration and pressurization.

The safety intended functions of the control room ventilation system are to maintain control

room temperature during normal and accident conditions and to maintain dose to control room

operators below the GDC-1 9 limits. In the event of a fire'in the cable enclosure below the

control room, the system prevents C02 intrusion into the control room. Therefore, 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).

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Emergency Diesel Generator Ventilation. The EDG ventilation system maintains temperatures in the EDG rooms within acceptable limits for operation of the diesel generators and associated

components, including the EDG control cabinets. The system also provides ventilation and

removal of fuel oil vapors from the fuel oil day tank enclosure and the fuel oil pump room.

The EDG ventilation system performs the safety intended function of maintaining a suitable

environment for the operation of the diesels. The system provides the additional FP function of

removing fumes from the diesel generator fuel oil day tank room and the fuel oil pump room.

Therefore, the EDG 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).

Switchgear Ventilation. The switchgear ventilation system maintains temperature in various

areas of the switchgear complex and N-train battery room within acceptable limits for operation of safety related equipment located in the rooms. Portions of the system provide a HELB

barrier. The switchgear ventilation system also prevents accumulation of combustible

concentrations of hydrogen gases inside the battery rooms.

The switchgear ventilation system performs the safety intended functions of maintaining room

temperatures for safety related equipment and providing a HELB barrier. The system also

performs a function related to FP. Therefore, the switchgear 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).

Containment Ventilation. The containment ventilation system maintains temperatures in the

various portions of the containment within acceptable limits for operation of equipment and for

personnel access for inspection, maintenance, and testing, as required. The system can also

purge the containment atmosphere to the environment via the plant vent and remove airborne

contamination from containment before personnel entry.

The containment ventilation system consists of several essentially independent subsystems, including the following:

* containment purge supply and exhaust system

* instrumentation room purge supply and exhaust system

* containment pressure relief system

* upper compartment ventilation system

* lower compartment ventilation system

* CRDM ventilation system

* reactor cavity ventilation system

* pressurizer compartment ventilation system

* containment instrumentation room ventilation system

* hot sleeve ventilation system

The CEQ system, which is another independent containment ventilation system, is treated as a

separate system (see Section 2.3.2.4 of this SER).

Of the independent subsystems included in the containment ventilation system, the only safety intended function is containment isolation, provided by certain system components.

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In accordance with 10 CFR 54.4(a)(2), nonsafety related component types in the containment

ventilation system are subject to an AMR if their failure could prevent satisfactory

accomplishment of a safety function. Housings, evaluated in Section 2.3.3.11 of this SER,

represent the only nonsafety related component type that requires an AMR pursuant to

10 CFR 54.4(a)(2).

The containment 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)(2).

Security Diesel Generator Room Ventilation. The security diesel generator room ventilation

maintains the security diesel generator room temperature. System components requiring an

AMR include the intake and exhaust fans and associated ductwork. This ventilation system is

considered part of the security system.

The security diesel provides power for emergency lighting for access to the N2 valves. The N2

valves are credited in the Appendix R safe-shutdown analysis and are considered safeshutdown equipment. Therefore, the security diesel is required to support the safe-shutdown

analysis, which brings the security diesel generator room ventilation within the scope of license

renewal based on the criteria of 10 CFR 54.4(a)(3).

Fuel Handling Area Exhaust. The fuel handling area exhaust system is a subsystem of the SFP

system discussed in Section 2.3.3.1 of this SER. Two 30,000 cubic feet per minute exhaust

fans associated with this system normally draw directly from the area. If the high radiation

setpoint is reached, a radiation monitor in the SFP area trips the supply fans to the fuel

handling area, opens the outlet dampers from the charcoal filters, and closes the dampers that

bypass the charcoal filter bed. This is done to minimize the consequences of a fuel handling

accident and minimize the release to the environs.

Therefore, the fuel handling area exhaust system performs a safety function and is within the

scope of license renewal based on the criteria of 10 CFR 54.4(a)(1).

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and CNP UFSAR Sections 5.5, 9.9, and 9.10 to

determine whether there is reasonable assurance that the applicant identified the HVAC

components within the scope of license renewal and subject to an AMR in accordance with

10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff used the evaluation methodology described in

Section 2.3 of this SER. The staff conducted its review in accordance with Section 2.3 of the

SRP-LR.

In conducting its review, the staff examined the UFSAR to determine if the applicant omitted

any safety-related system functions in accordance with the requirements of 10 CFR 54.4 as an

intended function of the control room area ventilation system. The staff did not identify any

omissions.

In addition, the staff evaluated system functions described in the LRA and UFSAR, in

accordance with the requirements of 10 CFR 54.4, to verify that the applicant did not omit

components having intended functions from the scope of license renewal. The staff also

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focused on components that the applicant did not identify as subject to an AMR to determine if

any components were omitted.

To verify that the applicant identified the components of the HVAC that are within the scope of

license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), the staff compared the referenced flow diagrams to the system drawings and descriptions in the UFSAR to ensure that the referenced flow diagrams are representative of the HVAC system. The staff then reviewed the referenced flow diagrams to verify that those

portions of the HVAC that meet the scoping requirements of 10 CFR 54.4 are included within

the scope of license renewal and are identified as such by the applicant in LRA Section 2.3.3.6.

The staff also sought to verify that the applicant identified all HVAC components within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.3.6 did not identify areas in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, the staff did not issue any RAIs to the applicant to determine whether the applicant properly applied the scoping criteria of 10 CFR 54.4 and the screening criteria of 10 CFR 54.21.

2.3.3.6.3 Conclusion

During its review of the information in the LRA, license renewal drawings, and licensing basis

information, the staff did not identify any omissions or discrepancies in the applicant's scoping results for HVAC components. The staff concludes that the applicant adequately identified the

HVAC components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the HVAC components that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

2.3.3.7 Fire Protection

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 FP system. The FP system rapidly detects and controls/suppresses fires while limiting their damage. The FP system comprises several FP subsystems and design features, including the following:

* fire detection system

* fire alarm and annunciation systems

* fire water supply distribution system

* fire water pumping systems

* water suppression systems

* gaseous suppression systems

* turbine bearing - dry chemical system

* manual fire fighting systems * fire barriers - plant layout

* penetration seals

* fire doors

* fire dampers

* raceway fire barrier materials

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* cable tray fire stops

* separation of engineered safety features actuation system and reactor protection

system - Marinite board and Quelpyre tape

* west motor-driven auxiliary feedwater pump enclosure, Units 1 and 2

* roof smoke and heat vents

* floor drains

The water supply for the fire water tanks is the municipal water supply.

The Appendix R safe-shutdown analysis credits the FP system because it supplies cooling

water to the security diesel, which powers lighting needed to achieve safe shutdown.

In accordance with 10 CFR 54.4(a)(2), nonsafety related portions of the system are subject to

an AMR if their failure could prevent satisfactory accomplishment of a safety function.

Components that require an AMR, based on the criteria of 10 CFR 54.4(a)(2), include liquidfilled FP components in the containment, auxiliary building, screenhouse, and the portion of the

turbine building that contains the AFW pumps. Because these portions of the system are also

within the scope of license renewal pursuant to 10 CFR 54.4(a)(3), no additional evaluation of

FP system components is required for 10 CFR 54.4(a)(2).

The FP system is within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(2)

and 10 CFR 54.4(a)(3).

In Table 2.3.3-7 of the LRA, the applicant identified the FP component types that are within the

scope of license renewal and subject to an AMR, including bolting, expansion joint, filter.

housing, fittings, flange, flex hose, heat exchanger (bonnet), heat exchanger (shell), heat

exchanger (tubes), heater housing, hydrant, level glass gauge, orifice, piping, pump casing,

silencer, spray nozzles, strainer, strainer housing, tank, tubing, and valve.

2.3.3.7.2 Staff Evaluation

The NRC regulations in 10 CFR 54.21 (a)(1) state that the applicant must identify and list those

SSCs that are within the scope of this part, as delineated in 10 CFR 54.4, and that are subject

to an AMR. The staff reviewed LRA Section 2.3.3.7, 'Fire Protection," to determine whether

there is reasonable assurance that the applicant appropriately identified the SSCs that serve FP

intended functions as within the scope of license renewal and subject to an AMR in accordance

with the requirements of -10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively. The staff

conducted its review, described below, in accordance with Section 2.3 of the SRP-LR.

The staff sampled portions of the UFSAR to identify any additional FP system functions that

meet the scoping requirements of 10 CFR 54.4 but that are not identified as an intended

function in the LRA. The staff also reviewed the plant's Fire Protection Program Manual

(FPPM). This manual directly references the plant's CLB documents and summarizes the Fire

Protection Program and commitments pursuant to 10 CFR 50.48 using the guidelines of

Appendix A to Branch Technical Position (BTP) Auxiliary and Power Conversion Systems

Branch (APCSB) 9.5-1. The staff reviewed portions of the FPPM to verify that the function of

the FP components relied upon to satisfy the provisions of Appendix A to BTP APCSB 9.5-1 are

included in the LRA and within the scope of license renewal as intended functions.

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The staff then compared the FP SSCs identified in the flow diagrams to verify that the applicant

highlighted the required components as within the evaluation boundaries on the flow diagram

and did not exclude them from the scope of license renewal. As part of the evaluation, the staff

also sampled portions of the same flow diagrams for the FP system to determine if any

additional portions of the system piping or components located outside of the evaluation

boundary should be identified as within the scope of license renewal.

In reviewing LRA Section 2.3.3.7, 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 to the applicant dated March 3, 2004, the staff issued an RAI concerning

these specific issues 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 following paragraphs

describe the staff's evaluation of the applicant's related responses to the RAls.

RAI 2.3.3.7-1

In RAI 2.3.3.7-1 (1), the staff requested information on LRA drawing 5152D concerning the note

at location D-6 that provides details on a deluge valve found on LRA drawing 5152M. The LRA

does not include this drawing, and the valve should be subject to an AMR. The applicant was

asked to clarify whether the deluge valve is within the scope of license renewal or justify its

exclusion.

In its response, dated September 21, 2004, the applicant stated that:

The reactor coolant pump (RCP) suppression system deluge valves are not

required by 10 CFR 50, Appendix R, or 10 CFR 50.48, and consequently do not

serve a license renewal function. The nonessential service water (NESW)

system, rather than the fire protection system, supplies water to these deluge

valves. Because the water supply for these deluge valves does not originate

from the in-scope fire protection system piping, which is depicted on license

renewal drawing LRA-12-5152D, a passive failure of these valves would not

prevent the fire protection system from supplying fire water to those portions of

the system that are required by 10 CFR 50.48.

Section I11.0 of Appendix R to 10 CFR 50 requires only a lubricating oil collection

system for the protection of the RCP area. 10 CFR 50, Appendix R does not

require a fire protection sprinkler system for the protection of this area. As

approved in the SER for the CNP exemption to the 10 CFR 50, Appendix R,

requirements applicable to the design of the CNP RCP motor lube oil collection

system [..], the existing RCP lube oil collection system provides a level of safety

equivalent to the technical requirements of 10 CFR 50, Appendix R, Section

111.0.

Therefore, the passive components of the deluge valves do not serve a license

renewal intended function, and consequently, are not subject to aging

management review.

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The applicant states that the deluge valves serve no license renewal function because there is

no interconnection to any required system; thus making the system not required. Based on its

review, the staff finds the applicant's response to RAI 2.3.3.7-1(1) acceptable. -

In RAI 2.3.3.7-1(2), the staff asked for further analysis of the control circuit instrumentation at

location H-5 on license renewal drawing LRA-12-5152D because it is connected to the FP

system via a 1-inch water line and a normally open valve. The staff asked the applicant to

clarify whether this item should be within the scope of license renewal or justify its exclusion.

In its response dated May 7, 2004, the applicant stated that the 1-inch line leading to SD-1 66 at

location H5 on license renewal drawing LRA-12-5152D constitutes station drain 166. Valve

1 2-ZSO-60 is normally open to ensure that there is no water accumulation in the dry pipe

header. Upon actuation of the fire suppression system in this area, solenoid-operated valve

12-ZSO-60 automatically closes to isolate the drain. The drain line downstream of valve

ZSO-60 is not part of the required flowpath and does not affect the function of the FP system.

Therefore, it is not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(2) acceptable

because this drain pipe serves no emergency function.

In RAI 2.3.3.7-1(3),;the staff requested clarification concerning the charcoal filters at locations

C-6, E-8, J-8, and L-6 (shown in details B-3, E-3, J-3, and M-3) on drawing LRA-12-5152E,

which have suppression components not highlighted as portions of the flow diagram within the

scope of license renewal and subject to an AMR. The staff asked the applicant to clarify

whether these items should be within the scope of license renewal or justify their exclusion.

In its response dated May 7, 2004, the applicant stated that the charcoal filters at locations C6,

E8, J8, and L6 on drawing LRA-12-5152E serve the containment pressure relief system

(1 -HV-CPR-1 and 2-HV-CPR-1) and the containment instrument room ventilation system

(1-HV-CIPX-1 and 2-HV-CIPX-1). These HVAC filters do not have a license renewal intended

function. The manual fire suppression capability provided by these fire water lines is not

required for 10 CFR 50.48; thus, these components are not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(3) acceptable

because upon review of UFSAR, Section 5.5.3, the staff found that the ventilation systems

involved are nonemergency-related systems.

In RAI 2.3.3.7-1(4), the staff requested further analysis of details D-6, D-9, K-3, K-6, and K-9 on

LRA drawing 5152J that show what appear to be dry-pipe sprinkler systems with the air

accumulator tanks (compressors) not highlighted as portions of the flow diagram within the

scope of license renewal and subject to an AMR. Details K-3 and K-6 also show valves and

supply piping, which are not highlighted, as portions of the flow diagram within the scope of

license renewal and subject to an AMR. The staff asked the applicant to clarify whether these

items should be within the scope of license renewal or justify their exclusion.

In its response dated May 7, 2004, the applicant stated that the ZRC-series components at

details D-6, D-9, K-3, K-6, and K-9 of drawing LRA-1-5152J are the retard chambers associated

with the alarm check valves for several wet-pipe sprinklers. The retard chambers provide an

alarm function and are active components that are not subject to an AMR. Components

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1 -ZFP-1 85 and 1 -ZFP-358 at details K-6 and K-3 are alarm check valves for the wet-pipe

sprinklers serving the north end of the turbine building and the abandoned diesel fire pump

room in the screenhouse, which are areas requiring FP, based on the criteria 10 CFR 50.48.

Therefore, these valves are subject to an AMR. The material and environment for the valves

and downstream piping are the same as those for valves and piping that are already included in

LRA Table 3.3.2-7. Component 1 -TK-236 at detail K-9 is the air receiver for the dry-pipe

sprinkler serving the main turbine lagging area. Loss of the air receiver would not prevent the

function of the dry-pipe sprinkler; therefore, this component is not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(4) acceptable

because the applicant identified the components which require an AMR. Retard chambers are

considered active and nonvital alarm components to FP systems; therefore, they are not

subject to an AMR.

In RAI 2.3.3.7-1(5), the staff requested further analysis of details C-6, H-6, L-6, D-9, and L-9 on

LRA drawing 5152K, which show what appear to be dry-pipe sprinkler systems with the air

accumulator tanks (compressors) not highlighted as portions of the flow diagram within the

scope of license renewal and subject to an AMR. Detail L-6 also shows valves and supply

piping to the diesel fire pump room, which are not highlighted, as portions of the flow diagram

within the scope of license renewal and subject to an AMR. The staff asked the applicant to

clarify whether these items should be within the scope of license renewal or justify their

exclusion.

In its response dated May 7, 2004, the applicant stated that the ZRC-series components at

details C-6, H-6, L-6, D-9, and L-9 of drawing LRA-2-5152K are the retard chambers associated

with the alarm check valves for the wet-pipe sprinklers. The retard chambers provide an alarm

function and are active components; therefore, they are not subject to an AMR. Components

2-ZFP-1 85 and 2-ZFP-358 at details H-6 and L-6 are alarm check valves for the wet-pipe

sprinklers serving the south end of the turbine building and the abandoned diesel fire pump

room in the screenhouse, which are areas requiring FP pursuant to 10 CFR 50.48. Therefore,

these valves are subject to an AMR. The material and environment for the valves and

downstream piping are the same as those for valves and piping that are already included in

LRA Table 3.3.2-7. Component 2-TK-237 at detail D-9 is the air receiver for the dry-pipe

sprinkler serving the main turbine lagging area. Loss of the air receiver would not prevent the

function of the dry-pipe sprinkler; therefore, this component is not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(5) acceptable

because the applicant identified the components which require an AMR. Retard chambers are

considered active and nonvital alarm components to FP systems; therefore, they are not

subject to an AMR.

In RAI 2.3.3.7-1(6), the staff requested further analysis of detail G-4 on LRA drawing 5152L,

which shows what appears to be a dry-pipe sprinkler system with the air accumulator tank

(compressors) not highlighted as portions of the flow diagram within the scope of license

renewal and subject to an AMR. Details G-7 and G-9 show the license renewal boundary

established at a normally open valve. The staff asked the applicant to clarify whether these

items should be within the scope of license renewal or justify their exclusion.

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-

In its response dated May 7, 2004, the applicant stated that the ZRC-series components at

detail G-4 of drawing LRA-12-5152L are the retard chambers associated with the alarm check

valves for two wet-pipe sprinklers. The retard chambers provide an alarm function and are

active components; therefore, they are not subject to an AMR. Components 12-ZFP-360,

12-ZFP-361, and 12-ZFP-169 at details G-7 and G-9 are the alarm check valves for areas

requiring FP, based on the requirements of 10 CFR 50.48. Therefore, these valves are subject

to an AMR. The material and environment for the valves and downstream piping are the same

as those for valves and piping that are already included in LRA Table 3.3.2-7. The other alarm

check valves at detail G-9 are for areas that do not require FP pursuant to 10 CFR 50.48;

therefore, they are not subject to an AMR. In the event of a failure of any components in this

normally pressurized water suppression FP header, station personnel will take appropriate actions to assure that system intended functions are maintained.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(6) acceptable because the applicant identified the components that require an AMR. Retard chambers are

considered active and nonvital alarm components to FP systems; therefore, they are not

subject to an AMR.

In RAI 2.3.3.7-1 (7), the staff requested further evaluation of detail G-3 on LRA drawing 5152N,

which shows what appears to be a dry-pipe sprinkler system with the air accumulator tank

(compressors) and drain not highlighted as portions of the flow diagram within the scope of

license renewal and subject to an AMR. In addition, detail E-7. shows a valve and sprinkler

supply for the auxiliary building drumming room and radiation waste material handling building

not highlighted as portions of the flow diagram within the scope of license renewal and subject

to an AMR. The staff asked the applicant to clarify whether these items should be within the

scope of license renewal or justify their exclusion.

In its response dated May 7, 2004, the applicant stated that the components at detail G-3 of

drawing LRA-12-5152N are the air compressor and receiver for a dry-pipe sprinkler. Loss of

the air receiver would not prevent the function of a dry-pipe sprinkler; therefore, this component is not subject to an AMR. Component 1 2-ZFP-264 at detail E-7 is the alarm check valve for the

auxiliary building drumming room, the radioactive waste material handling building, and the

Unit 2 personnel passageway. -.The auxiliary building drumming room/personnel passageway is

an area requiring FP based on the requirements of 10 CFR 50.48; therefore, this valve is

subject to an AMR. The material and environment for the valves and downstream piping are

the same as those for valves and piping that are already included in LRA Table 3.3.2-7. The

radioactive waste material handling building does not require FP pursuant to 10 CFR 50.48; thus, the associated water sprinkler piping is not subject to an AMR. In the event of a failure of

any components in this normally pressurized water suppression FP system header, station

personnel will take appropriate actions to assure system intended functions are maintained.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(7) acceptable, because some components identified are not required for the FP system and the areas

identified are outside of the scope of license renewal. The radioactive waste material handling building does not require FP on the basis of 10 CFR 50.48; thus the associated water sprinkler

piping is not subject to an AMR.

In RAI 2.3.3.7-1(8), the staff requested further explanation of detail L-3 on LRA drawing 5152R,

which shows a valve and sprinkler supply for the containment access building not highlighted as

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portions of the flow diagram within the scope of license renewal and subject to an AMR. The

staff asked the applicant to clarify whether these items should be within the scope of license

renewal or justify their exclusion.

In its response dated May 7, 2004, the applicant stated that the components at detail L-3 of

drawing LRA-12-5152R are the FP (water) supply components for the containment access!

building. This building houses the offices for the radiation protection department and serves as

the primary entry/exit point for the radiologically restricted area. It is not connected to seismic

structures, houses no safety-related equipment, and does not require FP pursuant to

10 CFR 50.48. Therefore, these FP components are not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(8) acceptable, because the protected area is outside the scope of license renewal. This office building does

not require FP on the basis of 10 CFR 50.48; therefore, its related FP components are not

subject to an AMR.

In RAI 2.3.3.7-1(9), the staff asked why locations C-2 and D-6 on LRA drawing 5152S show the

Lake Charter Township water supply not highlighted as a portion of the flow diagram within the

scope of license renewal and subject to an AMR. The staff requested the applicant to clarify whether this item should be within the scope of license renewal or to justify its exclusion.

In its response dated May 7, 2004, the applicant stated that the Lake Charter Township water

supply piping connections shown on drawing LRA-12-5152S are not credited for response to a fire pursuant to 10 CFR 50.48. The contained volume in the fire water storage tanks is

sufficient to extinguish the 10 CFR 50.48 design-basis fire without makeup from offsite sources.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(9) acceptable, because the lake supply is supplemental and not required for FP.

In RAI 2.3.3.7-1(10), the staff requested further analysis of location H-9 on LRA drawing 5152T, which shows the fire pump test header not highlighted as a portion of the flow diagram within

the scope of license renewal and subject to an AMR. The staff asked the applicant to clarify whether this item should be within the scope of license renewal or to justify its exclusion.

In its response dated May 7, 2004, the applicant stated that the fire pump test header and

associated components shown on drawing LRA-12-5152T are normally isolated from the fire

water header and do not provide a 10 CFR 50.48 FP function; thus, they are not subject to

AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(10) acceptable, because the test connection is isolated from the water header.

In RAI 2.3.3.7-1(11), the staff asked why locations F-6 and G-6 on LRA drawing 5153 show the

suppression system supply from normally open valves to the computer rooms not highlighted as

a portion of the flow diagram within the scope of license renewal and subject to an AMR. The

staff asked the applicant to clarify whether this item should be within the scope of license

renewal or to justify its exclusion, and to verify that the procedures include operator actions to close these valves when needed.

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In its response dated May 7, 2004, ,the applicant stated that the original FP carbon dioxide

suppression supply components for the computer rooms have been abandoned in place and

are no longer functional. As shown on drawing LRA-12-5153 at locations F-6 and G-6, blanking

flanges are installed downstream of valves 1-FCO-171 and 2-FCO-1 72.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1 (11) acceptable,

because abandoned systems are not within the scope of license renewal.

In RAI 2.3.3.7-1(12), the staff requested the applicant to provide the basis for the battery room

at location E78 on LRA drawing 5153G not appearing to have CO2 protection.- The staff asked

the applicant to verify whether some form of protection has been provided in this area or justify

the exclusion of fire suppression.

In its response dated May 7, 2004, the applicant stated that automatic fire suppression is not

provided for the Unit 2 AB battery room (fire zone 46D). This zone is equipped throughout with

early warning ionization detection, which will alert the control room operators of a fire condition,

allowing fire brigade personnel to be dispatched to the zone. Portable fire extinguishers and

water hose reels provide manual fire suppression.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1(12) acceptable

because it identified the FP features of the room.

RAI 2.3.3.7-2

In RAI 2.3.3.7-2(1), the staff inquired about the fire pump installation, which the applicant

indicated is in accordance with National Fire Protection Association (NFPA) 20, "Standard for

the Installation of Stationary Pumps for Fire Protection." However, the LRA drawings submitted

do not include a pressure maintenance pump. The staff asked the applicant to verify the

presence of a pressure maintenance pump and include it on the drawings. The applicant

should also state whether it is within the scope of license renewal and subject to an AMR.

In its response dated May 7, 2004, the applicant stated that the FP pegging pump (12-PP-146)

shown at location G5 on drawing LRA-12-5152T is the system pressure maintenance pump.

The pump is within the scope of license renewal and subject to an AMR. Tables 2.3.3-7 and

3.3.2-7 of the LRA include it in the component type "pump casing."

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-2(1) acceptable

because it identified an adequate pressure maintenance pump that is within the scope of

license renewal.

In RAI 2.3.3.7-2(2), the staff requested further discussion on the manually operated foam

suppression systems. The LRA drawings submitted do not show any foam systems. The staff

asked the applicant to verify the location of any foam suppression systems and show them on

the drawings. The applicant should also clarify.whether they are within the scope of license

renewal and subject to an AMR.

In its response dated May 7, 2004, the applicant stated that manually operated foam

suppression racks are provided in various locations in the turbine building and screenhouse.

Five-gallon cans of foam are monitored and sampled in accordance with plant procedures.

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They are considered consumables, analogous to fire extinguishers, and as such are not shown

on LRA drawings and do not require an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-2(2) acceptable because it identified, located, and discussed manually operated foam suppression. These

systems do not require an AMR.

In RAI 2.3.3.7-2(3), the staff requested further discussion of any halon systems. The LRA

drawings submitted do not show any halon systems. The staff asked the applicant to verify the

location of any halon fire suppression systems and show them on the drawings. The applicant should also clarify whether they are within the scope of license renewal and subject to an AMR.

In its response dated May 7, 2004, the applicant stated that the halon tanks (1 -TK-274A, B, C, E, F, and G and 2-TK-275A, B, C, E, F, and G) are shown at locations J6 to M6 and J9 to M9

on drawing LRA-12-5154A. This drawing shows the distribution components and piping to the

control room cable vaults, with some continued at locations G2 and G6 on drawing LRA-12-

5153L. These components are within the scope of license renewal and subject to an AMR.

The component type "tank," listed in LRA Tables 2.3.3-7 and 3.3.2-7 includes the tanks and

internal cylinder valves exposed to an internal halon environment. The component types "flex

hose," "piping," "spray nozzles," and "valve" listed in these tables include other components and

piping exposed to an internal air environment.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-2(3) acceptable because it identified, located, and discussed all halon systems and identified the AMR

requirements.

2.3.3.7.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing basis information, and RAI responses, the staff did not identify any omissions or discrepancies in the applicant's scoping and screening results for the components of the FP system. Therefore, the staff concludes that the applicant has adequately identified the FP system 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 FP system components that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.8 Emergency Diesel Generators

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 EDG system. The EDG system provides a reliable, automatic onsite power source with sufficient capacity to operate ESF and

protection system loads to ensure the safe shutdown of the reactor and mitigate the

consequences of a design-basis accident in the event offsite power is lost. Each diesel engine is equipped with its own auxiliaries, including the following:

* starting and control air

* fuel oil

* lubricating oil

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* -cooling water

* intake and exhaust systemr

* voltage regulator

* -controls

The safety intended function of the EDG system is to provide power to ESF and protection

system loads. The Appendix R safe-shutdown analysis credits the EDG as a potential source

of alternating current power for recovery from an SBO. Therefore, the EDG 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 2.3.3-8 of the LRA, the applicant identified the EDG component types that are within

the scope of license renewal and subject to an AMR, including bolting, compressor, dryer,

expansion joint, filter housing; fittings, flex hose, heat exchanger (shell), heat exchanger

(tubes), heater housing, level glass gauge, manifold (piping), orifice, piping, pneumatic cylinder,

pump casing, sight flow indicator, silencer, strainer, tank; thermowell, trap, tubing, and valve.

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8 and CNP UFSAR Section 8.4 to determine whether

there is reasonable assurance that the applicant identified the EDG system components within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1). The staff conducted its review in accordance with the guidance 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 verify 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 being within the scope of license renewal to verify 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's review of LRA Section 2.3.3.8 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. Therefore,

the staff issued RAIs to the applicant concerning these specific issues 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's RAls and the applicant's responses are described below.

RAI 2.3.3.8-1 -

The applicant showed several components as subject to an AMR on the EDG license renewal

drawings but did not list them in LRA Table 2.3.3.8 for EDG components subject to an AMR.

These components are passive and long-lived and serve a pressure boundary function; The

staff asked the applicant to justify the exclusion of the following components from Table 2.3.3.8:

a. intake manifold coolers with cooling coils, air receivers, air distributors, and turbocharger

housings

b. 3/4' fuel drips

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In its response dated May 7, 2004, the applicant stated the following about RAI 2.3.3.8-1:

a. As shown on license renewal drawings, Intake manifold aftercoolers, are

subject to an AMR and are included in component types "Heat exchanger

(shell)" and "Heat exchanger (tubes)" listed in LRA Table 2.3.3-8.

Starting air receivers are subject to an AMR and are included in

component type "Tank" listed in LRA Table 2.3.3-8. Air distributor

housings are subject to an AMR, but were omitted from LRA Tables

2.3.3-8 and 3.3.2-8. The carbon steel housing and copper alloy air

distributor ring have the intended function of pressure boundary and are

exposed to air internally and externally. The aging effect requiring

management for internal carbon steel surfaces exposed to air is loss of

material, which will be managed by the Preventive Maintenance Program.

The aging effect requiring management for the external carbon steel

surfaces exposed to air is loss of material, which will be managed by the

System Walkdown Program. There are no aging effects requiring

management for copper alloy exposed to air.

Turbocharger housings are subject to aging management review and are

included in component type "Compressor" listed in LRA Table 2.3.3-8.

b. Drip lines are not subject to aging management review. Refer to the

response to RAI 2.3.3.8-3

Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-1 acceptable,

because it clarifies that (1) intake manifold aftercoolers are included in the heat exchanger

component type, (2) starting air receivers are included in the tank component type, (3) air

distributors are subject to an AMR but were omitted from Table 2.3.3-8, (4) turbocharge

housings are included in the compressor component type, and (5) fuel drip lines are not subject

to an AMR. Therefore, the staff's concerns described in RAI 2.3.3.8-1 are resolved.

RAI 2.3.3.8-2

Table 2.3.3-8 of the LRA lists heater housing as a component type subject to an AMR.

However, the license renewal drawings show the lubricating oil filter electric heater housings as

excluded from an AMR. The staff asked the applicant to clarify whether these heaters

penetrate the pressure boundary of the system bypass oil filters and whether the parts of these

heaters that support the intended function of maintaining the pressure boundary are within the

scope of license renewal and subject to an AMR in accordance with the requirements of

10 CFR 54.4(a)(2) and 10 CFR 54.21(a)(1).

In its response, dated May 7, 2004, the applicant stated that electric heaters penetrate the

pressure boundary of the by-pass oil filters and are bolted to the bypass lube oil filter housings.

These heater housings are considered part of the by-pass lube oil filter housings; the filter

housings are evaluated with the component type, 'filter housing" in LRA Tables 2.3.3-8 and

3.3.2-8.

The portion of the electric heaters that form the by-pass lube oil filter pressure boundary should

have been highlighted on drawings LRA-1-5151A, LRA-2-5151A, and LRA-1-5151C, as was

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done on drawing LRA-2-5151 C. -the parts of these heaters that support the intended function

of maintaining the pressure boundary of the filter housings are subject to an AMR and are

included with the component type "filter housing" in LRA Tables 2.3.3-8 and 3.3.2-8. The

component type Theater housing" in LRA Table 2.3.3-8 refers to the lube oil heaters (QT-1 1

6-AB/CD), shown on drawings LRA-1 -5151A, LRA-1-5151 C, LRA-2-5151A, and LRA-2-5151 C

at location F9.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-2 acceptable

because the components in question are adequately represented under respective component

types and are listed in Table 2.3.3-8. Additionally, the portions of the electric heaters that form

a pressure boundary have been evaluated for an AMR. Therefore, the staff's concerns

described in RAI 2.3.3.8-2 are resolved.

RAI 2.3.3.8-3

The license renewal drawings show 3/4" contaminated drip lines to the engine room sump as

subject to an AMR. These lines continue on P&lDs 5180 and 12-5180, which are not included

in the license renewal drawing index. Therefore, the staff could not determine if the applicant

identified all the contaminated drip line components that meet the criteria of 10 CFR 54.4(a)(2)

as subject to an AMR and listed them as component types in LRA Table 2.3.3-8. To make this

determination, the staff asked the applicant to provide these drawings or text information to

identify the EDG fuel oil drip line components that are subject to an AMR in accordance with the

requirements of 10 CFR 54.21(a)(1).

In its response, dated May 7, 2004, the applicant stated that the drip lines to the engine room

sump shown on drawings LRA-1-5151 A, LRA-2-5151 A, LRA-1-5151 C, and LRA-2-5151 C were

highlighted in error. The contaminated drip lines are open-ended lines used for draining fuel oil

leakage to the engine room sump during engine operation. These drip lines do not have an

intended function that is in accordance with 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), or

10 CFR 54.4(a)(3). The supports for these drain lines that are required to provide structural

support (including seismic 11/l) are within scope of license renewal. The supports for these -

drain lines are included in the commodity type "piping supports" in LRA Tables 2.4-5 and

3.5.2-5, on pages 2.4-21 and 3.5-60, respectively.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-3 acceptable

because the applicant clarified that it highlighted the drip lines in error. The staff evaluated the

functions of these lines and finds the response to RAI 2.3.3.8-3 adequate. Therefore, the

staff's concerns described in RAI 2.3.3.8-3 are resolved.

RAI 2.3.3.8-4

License renewal drawings LRA-1-5151A, LRA-2-5151A, LRA-1-5151C, and LRA-2-5151C show

lubricating oil coolers. License renewal drawings LRA-1 -5151 B, LRA-2-5151 B, LRA-1-5151 D,

and LRA-2-5151 D show jacket water coolers as subject to an AMR. Table 2.3.3-8 does not list

heat exchanger channels and tubesheets, although the table does list heat exchanger shell with

an intended function of pressure boundary and heat exchanger tubes with an intended function

of heat transfer as components subject to an AMR. The staff asked the applicant to explain the

exclusion of the heat exchanger channels and tubesheets from Table 2.3.3-8.

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I

In its response dated May 7, 2004, the applicant stated that the channels and tubesheets of the

EDG lubricating oil coolers QT-11 0-AB/CD and jacket water coolers QT-1 31 -AB/CD are subject

to an AMR, but the applicant inadvertently omitted them from LRA Table 3.3.2-8. The

tubesheets of the lubricating oil and jacket water coolers are made of carbon steel and are

exposed to fresh raw water on one side and either lubricating oil or treated jacket water on the

other. The cooler channels are cast iron and are exposed to fresh raw water internally and air

externally. The applicant included the AMR results for these components in the response to

RAI 2.3.3.8-4.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-4 acceptable

because the applicant clarified that it omitted the heat exchanger channels and tubesheets from

Table 3.3.2-8 in error. The applicant evaluated these components in the LRA. Therefore, the

staff's concerns described in RAI 2.3.3.8-4 are resolved.

RAI 2.3.3.8-5

For those systems, structures, and components within the scope of license renewal in

accordance with 10 CFR 54.4, 10 CFR 54.21 (a)(1) requires the applicant to identify and list

those SCs subject to an AMR. The staff was unable to decide whether the applicant has

considered all the SCC's within the scope of license renewal to satisfy this requirement.

LRA Section 2.1.2.1.1 states that the identification of components subject to an AMR began

with the determination of the system evaluation boundary. The system evaluation boundary

includes those portions of the system that are necessary to ensure that the intended functions

of the system will be performed. Components needed to support each of the system-level

intended functions identified in the scoping process are included within the system evaluation

boundary.

The staff is unable to verify whether the applicant identified all the components that perform an

intended function because in its LRA, the applicant did not identify the components within the

system evaluation boundary. The staff needs to verify this information to effectively review the

LRA using the guidance in the SRP-LR.

The applicant was asked to confirm that the system components marked on license renewal

drawings for the EDG system depict all the components that perform an intended function. If

not, the applicant was asked to provide a list of those components that perform an intended

function but are not marked on license renewal drawings or provide revised drawings as

needed to include the additional components.

In its response dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings include all components that perform an intended function, with the

exception of structures, active and short-lived components, and those components that are

within the scope of license renewal and subject to an AMR based solely on the criteria of

10 CFR 54.4(a)(2). Active components that were screened out and not highlighted on flow

diagrams are those that do not meet the 10 CFR 54.21 (a)(1 )(i) criteria, as identified in

Appendix B to NEI 95-10, including items such as instrumentation, motors, and valve operators.

Instead of depicting process flow information, the diesel fuel oil equipment location plan

sketches included on license renewal drawings depict equipment layout. This information

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duplicates that shown elsewhere on the license renewal drawings for the EDGs; consequently,

the applicant did not highlight these equipment location plans.

The license renewal drawings do not depict any short-lived components that perform a

10 CFR 54.4 intended function. No EDG system components are within scope for the

10 CFR 54.4(a)(2) criteria.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-5 acceptable

because the applicant adequately identified and described the components. Therefore, the

staff's concerns described in RAI 2.3.3.8-5 are resolved.

RAI,2.3.3.8-6

The failure of nonsafety related components that could affect the ability of their associated EDG

to perform its intended function should be within the scope of license renewal in accordance

with 10 CFR 54.4(a)(2).

The EDGs have exhaust silencers that appear to support the EDG's intended functions. These

are long-lived, passive components. However, the applicant did not identify the exhaust

silencers on the license renewal drawings as within the scope of license renewal. The staff

asked the applicant to justify the exclusion of the exhaust silencers from the scope of license

renewal and from being subject to an AMR. -

In its responses dated August 19, 2004 and October 18, 2004 and in a telephone conference

dated September 1, 2004, the applicant stated that the exhaust silencers are included within the

scope of license renewal and are subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-6 acceptable

because the EDG exhaust silencers have been adequately identified as within the scope of

license renewal and are subject to an AMR. Therefore, the staff's concern described in RAI

2.3.3.8-6 is resolved. Commitment #37 in Appendix A of this SER cites the AMP that will

manage the aging effects for the EDG exhaust silencers.

RAI 2.3.3.8-7

The failure of nonsafety related components that could affect the ability of their associated EDG

from performing its intended function should be within the scope of license renewal in

accordance with 10 CFR 54.4(a)(2). The EDGs have centrifugal exhausters that appear to

support intended functions. These are long-lived, passive components. However, the applicant

did not identify the centrifugal exhausters on the license renewal drawings as within scope of

license renewal. The staff asked the applicant to justify the exclusion of the centrifugal

exhausters from the scope of license renewal and from an AMR.

In its response dated July 26, 2004, and by telephone conference dated September 1, 2004,

the applicant stated that the EDG centrifugal exhausters are nonsafety-related components in

the crankcase breather subsystem. This EDG subsystem maintains a slight vacuum in the

crankcase to remove vapors and minimize oil leakage. This function is not required for diesel

engine operation, and a failure of these components would not render-the EDG inoperable.

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Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-7 acceptable because the applicant gave adequate explanation about the function of the centrifugal exhausters and how their failure would not affect the EDG's intended function. Therefore, the

staff's concern described in RAI 2.3.3.8-7 is resolved.

2.3.3.8.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing basis information, and RAI responses, the staff did not identify any omissions or discrepancies in the applicant's scoping and screening results for the SCs of the EDG system. Therefore, the

staff concludes that the applicant adequately identified the EDG SCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified

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

2.3.3.9 Security

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 security system. The security system protects against radiological sabotage pursuant to 10 CFR Part 73 and provides adequate lighting for access to the N2 valves to perform safe-shutdown functions (Section IIIJ.of

Appendix R to 10 CFR Part 50). The security system consists of the security diesel generator, lights, alarms, doors, intrusion detection devices, metal detectors, explosive detectors, gates, and communication equipment.

The security diesel provides power for emergency lighting for access to the N2 valves. The

Appendix R safe-shutdown analysis credits the N2 valves as safe-shutdown equipment. Therefore, the security diesel is required to support the safe-shutdown analysis, and the system is within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(3).

Section 2.3.3.6 of the LRA evaluates the security diesel generator room ventilation with the

HVAC systems.

In Table 2.3.3-9 of the LRA, the applicant identified the security component types that are within

the scope of license renewal and subject to an AMR, including bolting, compressor casing, expansion joint, filter housing, fittings, flange, flex hose, heat exchanger (shell), heat exchanger (tubes), heater housing, piping, pump casing, silencer, strainer, strainer housing, tank, thermowell, tubing, and valve.

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 to determine whether there is reasonable assurance

that the applicant identified the security system components within the scope of license renewal

and subject to an AMR, in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff

used the evaluation methodology described in Section 2.3 of this SER. The staff conducted its

review in accordance with the guidance in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify that the applicant did not inadvertently omit from the scope of license renewal

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any components with intended functions delineated under 10 CFR 54.4(a). The staff then

reviewed those components that the applicant identified as being within the scope of license

renewal to verify 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's review of the LRA Section 2.3.3.9 identified areas in which additional information

was necessary to complete the review of the applicant's scoping and screening results. -

Therefore, the staff issued RAls to the applicant concerning these specific issues 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's RAls and the applicant's responses are described

below.

RAI 2.3.3.9-1

Licensedrenewal drawing LRA-12-5150B shows a vent as subject to an AMR. However, LRA

Table 2.3.3-9 does not list the component group "vent." The staff asked the applicant to clarify

whether vents are considered part of the component group "piping" in Table 2.3.3-9. If not, the

staff asked the applicant to justify the exclusion of this component from an AMR in accordance

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

In its response dated May 7, 2004, the applicant stated that the fuel oil tank vent piping shown

on drawing LRA-1 2-5150B is subject to an AMR and is included in the component type Upiping'

listed in LRA Table 2.3.3-9.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-1 acceptable

because it clarifies that the component type "'piping" in LRA Table 2.3.3-9 includes vents.

Therefore, the staff's concern in RAI 2.3.3.9-1 is resolved.

RAI 2.3.3.9-2

The staff asked the applicant to clarify whether the components of the security diesel generator

shown on license renewal drawing LRA-1 2-5150B are treated as a complex assembly. If the

security diesel generator is treated as a complex assembly, the applicant must identify the

boundaries of the security diesel generator so that the staff may determine whether its.

subcomponents are subject to an AMR in accordance with the requirements of

10 CFR 54.4(a)(3) and 10 CFR 54.21(a)(1).

In its response dated May 7, 2004, the applicant stated that the security diesel generator is

considered a'complex assembly for the CNP LRA. The mechanical subsystems of the security--

diesel generator are subject to an AMR. The applicant identified the security diesel generator

components subject to an AMR in LRA Table 2.3.3-9. The diesel generator engine itself is an

active component.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-2 acceptable

because it clarifies that the security diesel engine is the boundary, of the complex mechanism

and that the subsystems are subject to an AMR. Therefore, the staff's concern in RAI 2.3.3.9-2

is resolved..

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RAI 2.3.3.9-3

License renewal drawing LRA-12-5150B shows two jacket water coolers within the scope of

license renewal and subject to an AMR. The staff asked the applicant to clarify whether LRA

Table 2.3.3-9 lists these jacket water coolers as part of the component type "heat exchanger" and subject to an AMR. If not, the staff asked the applicant to justify the exclusion of these

components from Table 2.3.3-9.

In its response dated May 7, 2004, the applicant stated that the jacket water coolers 12-HE-68-l

and 12-HE-68-2 are subject to an AMR and are included in the component types "heat

exchanger (shell)" and "heat exchanger (tubes)" listed in LRA Table 2.3.3-9.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-3 acceptable because it clarifies that the component types "heat exchanger (shell)" and "heat exchanger (tubes)" in LRA Table 2.3.3-9 include the jacket water coolers. Therefore, the staff's concern in

RAI 2.3.3.9-3 is resolved.

RAI 2.3.3.9-4

For those SSCs within the scope of license renewal in accordance with 10 CFR 54.4, 10 CFR 54.21 (a)(1) requires the applicant to identify and list those SCs subject to an AMR.

The staff could not determine if the applicant considered all the SSCs within the scope of

license renewal to satisfy this requirement.

Section 2.1.2.1.1 of the LRA states that the identification of components subject to an AMR

begins with the determination of the system evaluation boundary. The system evaluation

boundary includes those portions of the system that are necessary to ensure that the intended

functions of the system will be performed. Components needed to support each of the system- level intended functions identified in the scoping process are included within the system evaluation boundary.

The staff could not verify whether the applicant identified all the components that perform an

intended function, because in its LRA the applicant did not identify the components within the

system evaluation boundary. The staff must verify this information to effectively review the LRA

using the guidance of the SRP-LR.

The staff asked the applicant to confirm that the system components marked on license

renewal drawings for the security diesel system depict all the components that perform an

intended function. If not, the staff asked the applicant to provide a list of those components that

perform an intended function but are not marked on license renewal drawings, or to provide revised drawings as needed to include the additional components.

In its response dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings indicate all components that perform an intended function, with the

exception of structures, active and short-lived components, and those components that are

within scope and subject to an AMR based solely on the criteria of 10 CFR 54.4(a)(2). ,Active

components that were screened out and not highlighted on flow diagrams are those that do not

meet the 10 CFR 54.21(a)(1)(i) criteria, as identified in Appendix B to NEI 95-10, which includes

items such as instrumentation, motors, and valve operators.

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The applicant did not depict any short-lived components that perform a 10 CFR 54.4 intended

function on license renewal drawings. No security diesel system components are within scope

for the 10 CFR 54.4(a)(2) criteria.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-4 acceptable,

because the security system components that are highlighted on the license renewal drawings

have been adequately described. Therefore, the staff's concerns described in RAI 2.3.3.9-4

are resolved.

2.3.3.9.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the security system. Therefore,

the staff concludes that the applicant adequately identified the security system SCs that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

adequately identified the security system SCs that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.10 Post-Accident Containment Hydrogen Monitoring

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 postaccident containment hydrogen

monitoring system (PACHMS). The PACHMS monitors the containment atmosphere forhydrogen concentrations following a LOCA to assist in determining the need for initiation of the

hydrogen recombiners. The PACHMS comprises two sampling-analyzing control trains. -Each

train has a hydrogen analyzer panel and a remote control panel. The PACHMS can take

samples from nine locations within the containment. After analysis, the sample is returned to

the containment.

The primary safety intended functions of the system include sampling and analyzing

containment hydrogen following an accident and providing containment isolation. Therefore,

the PACHMS is within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(1).

In Table 2.3.3-10 of the LRA, the applicant identified the PACHMS component types that are

within the scope of license renewal and subject to an AMR, including analyzer body, bolting,

filter, fittings, flex hose, heat exchanger, moisture separator, orifice, piping, pump casing, and

valve.

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 and UFSAR Section 7.8 using 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 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 verify that the applicant did

not inadvertently omit from the scope of license renewal any components with intended

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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 verify 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 PACHMS that meet the scoping requirements of 10 CFR 54.4 within the scope of license renewal, and it identified them as such

in LRA Section 2.3.3.10. The staff also found that LRA Table 2.3.3-10 includes the PACHMS

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.

2.3.3.10.3 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 PACHMS. Therefore, the staff concludes that the applicant adequately identified the PACHMS SCs that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the

PACHMS 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 scope for 10 CFR 54.4(a)(2). The applicant's scoping effort took place before the development of

industry guidance on scoping based on the criteria of 10 CFR 54.4(a)(2). Consequently, the

applicant undertook a separate scoping effort to incorporate existing industry guidance (specifically, spatial interaction). This section discusses the result of this additional scoping effort. The applicant identified systems within the 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 the LRA. These

systems may be categorized into two groups:

(1) systems that are within the scope of license renewal for 10 CFR 54.4(a)(1) or

10 CFR 54.4(a)(3), as well as 10 CFR 54.4(a)(2), whose AMR results are presented in

sections other than Section 3.3.2.1.11 of the LRA

(2) systems that are within the scope of license renewal based solely on the criteria of

10 CFR 54.4(a)(2), whose AMR results are presented in Section 3.3.2.1.11 of the LRA

As discussed in the system descriptions, some of these systems in the second group have

components that are included in the evaluation of other systems, such as containment isolation.

Group 1 Systems. For systems in Group 1, the environment and materials are the same for the portion of the system affected by 10 CFR 54.4(a)(2) as for those portions evaluated under

10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3). Therefore, the AMR results discussed for these

systems in Section 3 of the LRA also apply to the portion of the system affected by 10 CFR 54.4(a)(2). Section 3.3.2.1.11 does not include components from these systems.

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The following are Group 1 systems:

* blowdown

* component cooling water

* chemical and volume control

* essential service water

* . feedwater , -

* , main steam

* reactor coolant

* fire protection

Group 2 Systems. Group 2 systems are within the scope of license renewal based on the

criteria of 10 CFR 54.4(a)(2), described below. Section 3.3.2.1.11 of the LRA presents the

AMR results for' those portions of the system affected by 10 CFR 54.4(a)(2). Table 2.3.3-11 of

the LRA lists the components in these systems that were evaluated based on the requirements

of 10 CFR 54.4(a)(2). In some cases, components in these systems are included in other

system evaluations. As appropriate, these are noted to provide a complete system description.

Auxiliary Steam. The auxiliary steam (AS) system provides reduced-pressure steam to various

plant subsystems to support plant operation. The AS system supplies certain subsystems,

including plant heating, steam jet air ejectors, turbine steam seals, and FP. The AS system is

in the form of a ring header and is cross-connected between the CNP units. The plant heating

boiler supplies steam to the AS system when both units are out of service.

Chemical Feed. The chemical feed system injects chemicals for pH and dissolved oxygen

control into the condensate system and into the steam generators. The chemical feed system

includes the condensate and feedwater chemical tanks, pumps, and piping. Section 2.3.4.1 of

the LRA evaluates the safety related isolation valves and piping in the chemical feed lines to the

main feedwater headers within the main feedwater system.

Containment. Containment includes mechanical components providing containment drainage.

Containment drainage collects and transports liquid from floor, equipment, and ice condenser

equipment drains to the waste disposal system via drain pots or sumps. Certain components

used for containment drainage are subject to an AMR, based on the criteria of

10 CFR 54.4(a)(2), and are not covered by any other.AMR. Structural portions of containment

are evaluated in LRA Section 2.4.1. Bulk structural commodities are evaluated in LRA Section

2.4.5.

Demineralized Water. The demineralized water system produces high-purity, degassified water

for makeup to the RCS and condensate-feedwater systems and to other plant services. Lake

water from the nonessential service water-(NESW) system is filtered, chlorinated, and held in a

retention' tank to effect complete sterilization. An alternate source of supply is the Lake Charter

Township public water system.

The demineralized water system includes containment penetrations that supply'demineralized

water to'the refueling cavity and containment pipe tunnel during outages. Under accident

conditions, these penetrations provide containment isolation. Section 2.3.2.2 of the LRA

evaluates containment isolation components.

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Process Drains. The process drains system collects drainage from various process systems. The system collects drainage from the waste evaporator and north and south boric acid

evaporators, pumping it to the miscellaneous drain tank. It also collects drainage from various

secondary plant SSCs and directs it either to the main condenser for reuse or to the turbine

room sump for discharge.

Ice Condenser. The ice condenser system provides a flowpath and sufficient ice to absorb

thermal energy from a LOCA or a MSLB to limit containment pressure rise to less than design

pressure immediately following an accident. The ice condenser system assists in iodine

removal from the containment atmosphere and provides an inventory source for the

containment recirculation sump to support sump recirculation level, pH, and boron

requirements. The ice condenser system refrigeration components maintain the ice bed

temperature within analyzed limits and replenish the ice beds during outages. The ice

condenser system includes the following:

* system structural steel

* ice baskets

* pressure-activated doors

* various components that cool the ice bed

The ice baskets that support the ice blowdown flowpath pressure-activated doors and

associated structural components provide the safety intended functions of the system (postaccident containment pressure and temperature control, iodine removal, and sump inventory source). Sections 2.4.1 and 2.4.5 of the LRA evaluate these components along with

structural components. Safety related portions of the system refrigeration components also

provide containment isolation when required. Section 2.3.2.2 of the LRA evaluates containment

isolation components.

Lake Charter Township Water. The Lake Charter Township water system supplies water for

the makeup pretreatment and filtration plant and the dedicated FP water supply tanks. The

Lake Charter Township water system also supplies cooling water for the NESW pump seals

and potable water for the plant site.

Nonessential Service Water. The NESW system provides cooling water to various plant heat

loads that have no safety functions. The NESW system supplies heat loads, including the

turbine oil coolers, air compressors, upper and lower containment ventilation units, and RCP

motor air coolers. The NESW pumps take suction from either CNP, Unit 1 or Unit 2, circulating water (CW) intake tunnels or discharge tunnels and discharge into either CNP, Unit 1 or Unit 2, CW discharge tunnels.

The NESW lines to containment are isolated during accident conditions. Section 2.3.2.2 of the

LRA evaluates the containment isolation components.

Nuclear Sampling. The purpose of the nuclear sampling (NS) system is to process and

condition representative samples from designated plant fluid systems for in-line analyzers and

grab samples for laboratory analysis. Samples are drawn from the following sources:

* pressurizer steam space

* pressurizer liquid space

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* two reactor coolant hot legs (loops 1 and 3)

* each of the four accumulators

* two RHR lines -

* CVCS letdown line at the demineralizer inlet and outlet headers

* volume control tank gas space

* -each of the four steam generator blowdown lines

The safety intended functions of the NS system are to provide containment isolation and to

maintain the pressure boundary of the safety related system being sampled, including the

RCPB. Maintaining the RCPB also supports the Appendix R safe-shutdown analysis and the

SBO event. -Therefore, this 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), as well as 10 CFR 54.4(a)(2).

This section evaluates the NS system components that meet the criteria of 10 CFR 54.4(a)(2).

The remaining components of the NS system subject to an AMR are evaluated with a number

of different systems. Portions of the NS system that have the safety related function of

maintaining the system pressure boundary are evaluated in the respective system review as

follows:

* RCS in Section 2.3.1 of the LRA

* ECCS in Section 2.3.2.3 of the LRA

* blowdown in Section 2.3.4.4 of the LRA

* main steam in Section 2.3.4.2 of the LRA

Containment penetration isolation components for sample lines from various systems in

containment are evaluated either with the sampled system or as part of the consolidated

containment isolation evaluation in Section 2.3.2.2 of the LRA.

Post-Accident Sampling. The postaccident sampling system (PASS) provides representative. -

samples for laboratory analysis following a LOCA. The system is common to CNP, Units 1 and

2. Samples are provided from RCS loop 1 and 3 hot legs, the pressurizer steam space, the

containment sump, and the RHR system. Provisions have been made for drawing gas samples

in each unit from the containment air space. These samples can be analyzed by in-line

equipment or collected and transported to the laboratory in a shielded container.

Section 2.3.2.2 of the LRA evaluates components in the PASS that provide containment

isolation.

Primary Water. The primary water system supplies water to miscellaneous services within the

auxiliary building and the containment, primarily for reactor coolant makeup. Major components

include the primary water storage tanks and primary water pumps.

The primary water line to containment is isolated in accident conditions. Section 2.3.2.2 of the

LRA evaluates containment isolation components.

Radioactive Waste Disposal. The radioactive waste disposal system collects and processes

liquid, gas, and solid radioactive wastes. The gaseous waste subsystem collects and

processes potentially radioactive gases discharged from various components and systems for

recycling, storage, and discharge at concentrations below the regulatory limits. The liquid

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waste subsystem collects, processes, and stores radioactive liquid waste from various plant

systems and drains in the auxiliary building and containment. The solid waste subsystem

stores resin for a short decay time before subsequent packaging for shipment and provides for

compression and drumming of solid wastes.

Section 2.3.2.2 of the LRA evaluates components in the radioactive waste disposal system that

provide containment isolation.

Station Drainage. The station drainage system collects spillage, drains, and overflows in the

auxiliary building, containment, and turbine building. Collected fluids are routed to various

sumps for disposal. The system includes station drainage piping, floor drains, and sump

pumps.

Section 2.3.2.2 of the LRA evaluates containment isolation components associated with this

system.

Spent Fuel Pool Cooling. SFP cooling removes, from the SFP, the heat generated by stored

spent fuel elements. The components of the CNP SFP cooling provide no intended functions.

The spent fuel pit provides the maintenance of pool inventory, which assures cooling, as

discussed in Section 2.3.3.1 of the LRA. The two units share the SFP. The design

incorporates two separate cooling trains sharing a common return line to the SFP. Piping is

arranged so that failure of any pipe does not drain the SFP below the top of the stored fuel

elements.

The clarity and purity of the SFP water is maintained by passing the cooling flow through a filter

and a demineralizer. Skimmers are provided to prevent dust and debris from accumulating on

the surface of the water. The refueling water purification pump and filter can be used

separately or in conjunction with the SFP demineralizer to regain refueling water clarity after a

crud burst in either unit. SFP cooling is also used to maintain water quality in the RWSTs of

both units.

Screen Wash System. The screen wash system supplies water from Lake Michigan (the

ultimate heat sink) to the CW system and the ESW system for CNP, Units 1 and 2, and returns

it to the lake. Traveling water screens are provided in the intake structure to remove debris and

fish. The screen wash system includes the following components:

* intake crib

* intake piping

* discharge piping

* forebay

* traveling screens (i.e., baskets, drives, and trash collection)

* screen wash pumps

* associated valves and sluice gates

The intended function of this system is to provide a flowpath to and from the ultimate heat sink

to the ESW system via the intake and discharge tunnels. Failure of this function, performed by

nonsafety related equipment, could affect a safety function. For license renewal, Section 2.4.3

of the LRA evaluates this equipment with the screenhouse structure. Therefore, this section

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does not evaluate any components in the screen wash system. The screen wash system does

not have the potential for spatial interaction with safety related equipment.

Radiation Monitoring. The'radiation monitoring system (RMS) detects, computes, and records

radiation levels. The RMS comprises a collection of small, independent systems located at

selected points in and around the plant. These systems are composed of area monitors,

process monitors, and environmental monitors.

The RMS has a containment isolation function. Section 2.3.2.2 of the LRA evaluates

containment'isolation components associated with this system.

Ventilation Systems-Auxiliary Building Ventilation. Miscellaneous Ventilation, and Containment

Ventilation. As described in UFSAR Section 9.9, the auxiliary building ventilation system (VA)

encompasses four different ventilation subsystems in the auxiliary building. The organization of

these subsystems in this application is consistent with their safety functions. Section 2.3.3.6 of

the LRA describes the ESF ventilation and fuel handling area exhaust (fuel handling

ventilation). The'two remaining auxiliary building Veritilation subsystems, as-described in

UFSAR Section 9.9, are the general ventilation systems and the general supply system. Other

than the potential for spatial interactions with safety related equipment, no auxiliary building

ventilation functions meet the criteria for inclusion within the scope of license renewal.

The miscellaneous ventilation system includes ventilation subsystems in various locations

throughout the plant site. The ventilation subsystems maintain appropriate environmental

conditions for the location served. Other than the potential for spatial interactions with safety

related equipment, no miscellaneous ventilation functions meet the criteria for inclusion within

the scope of license renewal.

Section 2.3.3.6 of the LRA describes the containment ventilation system, and it has

components evaluated with the ventilation systems. As discussed below, certain fan housings

are included with the AMR results in Section 3.3.2.1.11 of the LRA.

In these three ventilation systems, the majority of passive, nonsafety related components

contain only air and therefore do not require an AMR. However, components that contain liquid

require an AMR. Some of these components (cooling coils) are contained in packaged

ventilation units that isolate these components from leakage or spray onto safety related

components. Housings for these ventilation units are subject to an'AMR.' -

Components not contained in housings are part of chilled water systems that supply cooling

water to ventilation units in the auxiliary building ventilation and miscellaneous ventilation

systems. These components are in the auxiliary building and consist of the following:

* bolting

* -condensers

* strainers

* pumps

* valves

* tanks

* glass level gauges

tubing and piping

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In Table 2.3.3-11 of the LRA, the applicant identified the miscellaneous systems within scope for 10 CFR 54.4(a)(2) component types that are within the scope of license renewal and subject to an AMR, including bolting, condenser shell, evaporator housing, filter housing, flex hose, heat exchanger (shell), heater coil, heater housing, level glass gauge, manifold (piping), orifice, piping, pump casing, strainer housing, tank, thermowell, trap, tubing, valve, and ventilation unit

housing.

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 and CNP UFSAR Sections 5.3, 5.5, 9.4, 9.6, 9.8.3, 9.9, 10.6, 10.9, 10.10, 11.1, 11.1.2.1.4, and 11.3 to determine whether there is reasonable

assurance that the applicant identified the nonsafety related mechanical components within the

auxiliary steam, chemical feed, containment drainage, demineralized water, process drains, ice

condenser, Lake Charter Township water, nonessential service water, nuclear sampling, post-accident sampling, radioactive waste disposal, station drainage, SFP cooling, screen

wash, and radiation monitoring and ventilation systems that are within the scope of license

renewal and subject to an AMR in accordance with the criteria of 10 CFR 54.4(a)(2) and

10 CFR 54.21 (a)(1), respectively. The staff conducted its review in accordance with SRP-LR, Section 2.3 guidance.

In its review, the staff selected system functions described in the LRA and UFSAR that were set

forth in 10 CFR 54.4(a) to verify that components having intended functions were not omitted

from the scope of license renewal. The staff then reviewed the components within the scope of

license renewal in accordance with 10 CFR 54.4(a) to verify that passive and long-lived components were not omitted from being subject to an AMR in accordance with

10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.3.11 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. Therefore, the staff issued RAls to the applicant concerning these specific issues 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's RAls and the applicant's responses are described below.

RAI 2.3.3.11-1

Section 2.3.3.11 of the LRA describes 17 systems within the scope of license renewal and

subject to an AMR based on the criteria of 10 CFR 54.4(a)(2). However, the applicant did not

explain how failure of these systems or components within these systems may affect the

safety-related components/systems intended functions. The staff asked the applicant to

provide additional information which describes how failure of these nonsafety-related systems results in the failure of a safety-related system or component to perform its intended function.

In its response dated May 7, 2004, the applicant stated that the criteria for nonsafety-related SSCs whose failure could prevent the accomplishment of safety functions are either functional

or spatial. In a functional failure, the nonsafety-related SSC fails to perform its normal function

thereby impacting a safety function. In a spatial failure, the loss of structural or mechanical

integrity of a nonsafety-related SSC in physical proximity to a safety-related component impacts

a safety function of the safety-related component.

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The applicant provided two tables that identify by system and building location the

nonsafety-related component types meeting the criteria of 10 CFR 54.4(a)(2). The tables

identify how the failure of the component type potentially affects a safety related SSC.

Based on its review, the staff finds the applicant's response to RAI 2:3.3.11-1 acceptable

because it adequately describes the types of component failures and their effects on

components meeting the criteria of 10 CFR 54.4(a)(2). Therefore, the staff's concern in RAI

2.3.3.11 -1 is resolved.

RAI 2.3.3.11-2

Table 2.3.3-11 of the LRA identifies component types and intended functions as a group for 17

systems. The staff could not'identify which component types and intended functions in the

table correlate to which of the 17 systems described in LRA Section 2.3.3.11. The applicant did

not provide license renewal drawings for these systems, and the UFSAR does not provide

sufficient descriptive information. Therefore, the staff could not conclude whether the applicant

identified the mechanical system components for these systems that are within the scope of

license renewal and subject to an AMR. To make this determination, the staff asked the

applicant to provide drawings or text information which identify the components by system that

are subject to an AMR because they meet the intended function of 10 CFR 54.4(a)(2) and

10 CFR 54.21 (a)(1). If LRA Table 2.3.3-11 excludes any of these components, the staff asked

the applicant to revise the table.

In responses dated May 7, 2004 and September 2, 2004, as well as discussions during an

August 24, 2004 teleconference, the applicant stated that nonsafety-related components

containing liquid or steam located in the containment building, auxiliary building, screenhouse,

and the portion of the turbine building that contains the AFW pumps are considered to be

subject to an AMR unless no safety related equipment is in the area. The applicant further

described the area containing these components as a plant space that is on the same floor

(elevation) in a building with no barrier walls between the nonsafety related fluid-filled system

and the safety related components. At CNP, areas are identified with room numbers.

Structural walls form the boundary of a room on the same elevation of a major building and

separate safety related components from a spray or a leak from a nonsafety related

component. These walls are within the scope of license renewal and subject to an AMR. The

applicant further explained that if no safety related components are installed in the same area

as the nonsafety related fluid-filled components, then these nonsafety related components do

not meet 10 CFR 54.4(a)(2) and are not included within the scope of license renewal. The

applicant discussed examples of components that are excluded from the scope of license

renewal.

Based on its evaluation, the staff finds the applicant's responses to RAI 2.3.3.11-2 acceptable

because the staff did not find any omissions of nonsafety related components subject to an

AMR. In addition, the staff concludes that the applicant defined the population of components.

within 'the scdpe'of license renewal, in accordance with 10 CFR 54.4(a)(2). The staff considers

its concern described in RAI 2.3.3.11-2 resolved.

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RAI 2.3.3.11-3

The LRA implies that the SFP cooling system does not perform an intended function as defined

in 10 CFR 54.4. In addition, license renewal drawings show portions of the CCW system piping between the license renewal boundary flags to and from the spent fuel pit heat exchangers as

excluded from an AMR. However, UFSAR Section 9.4.1 states, "Any spent fuel pool off-loading scenario, including a full core off-load of two units, which meets the 82 0C (180 OF) peak bulk

pool temperature with one train of cooling and 5.8 hours to boil criteria is acceptable."

From this statement, it is not clear that water in the SFP can maintain sufficient shielding and

prevent the release of radioactive gases, given the 82 0C (180 IF) peak bulk pool temperature and 5.8 hour time to boil criteria without activation of at least one cooling train. The staff asked

the applicant to justify why at least one train of SFP cooling is not within the scope of license

renewal in accordance with 10 CFR 54.4(a).

In its response dated May 7, 2004, the applicant stated that the SER for CNP License

Amendments 260 and 243 provides the basis for the UFSAR statement cited above. The

UFSAR statement evaluated conditions related to the approval of a change to shorter starts of

core offload dependent on maximum ultimate heat sink temperatures during two periods in a

year.

The SER concludes the following:

For planned refueling conditions with both cooling trains in service, SFP water

temperature will stay below 142.3 OF, which is below the long term SFP design temperature of 150 OF. In the event that one SFP cooling train fails, the

remaining SFP cooling train will maintain SFP temperature below the SFP design temperature of 180 OF.

In the unlikely event of a sustained loss of both SFP cooling trains, the available

makeup capacity exceeds the maximum potential rate of evaporative losses, and

these makeup sources can be aligned within the time available prior to the onset

of boiling. Therefore, the staff concludes that the reliability and capacity of SFP

cooling and makeup systems are adequate to deal with the increased heat load, resulting from the proposed reduction in decay time.

The reference to the 82 0C (180 OF) peak bulk pool temperature in the cited UFSAR statement

reflects the evaluation of the loss of one train of SFP cooling. The reference to the 5.8-hour

time to boil criteria reflects the evaluation for loss of all SFP cooling.

In its response to RAI 2.3.3.1-1 dated September 2, 2004, the applicant credits the FP system to provide adequate makeup to the SFP in the event of loss of fuel pool cooling capability. The

FP system is in the scope of license renewal. Its capability is in excess of capacity required to

maintain pool water level at the maximum potential rate of evaporative losses. However, the FP

system alone does not provide the diversity of makeup water sources specified within the

licensing basis of the facility. This issue has been addressed in Section 2.3.3.1.

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2.3.3.11.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the miscellaneous systems.

Therefore, the staff concludes that the applicant has adequately identified the miscellaneous

system S~s that are within the scope of license renewal, as required by"10 CFR 54.4(a), and

that the applicant has adequately identified the miscellaneous system SCs that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.12 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 the miscellaneous systems. This

section discusses various systems that are within the scope of license renewal, but the

components subject to an AMR have been included in the mechanical system reviews or the

structural reviews. The systems' descriptions include discussions of the components subject to

an AMR and references to the sections containing the component evaluations.

Material/Equipment Handling. The material/equipment handling (MATL) system safely moves

material and equipment as required to support operations and maintenance activities. The

system consists of plant cranes (including associated components such as trolleys and bridges)

that lift, control, and transport loads in the auxiliary building, turbine building, containment,'

screenhouse, service building, sewage treatment building, radioactive waste handling building,

and other miscellaneous buildings.

Major equipment in the MATL system includes the following:

* east auxiliary building crane

* west auxiliary building crane

* containment polar cranes

* main turbine building crane

* auxiliary turbine building cranes

* ice condenser cranes

The normal functions of the MATL system do not require that the system be included within the

scope of license renewal. However, the system is included because of the potential for spatial

interactions with safety related equipment, which is in accordance with 10 CFR 54.4(a)(2).

Section 2.4 of the LRA evaluates the cranes as structural components.

Nuclear Fuels. The nuclear fuel (NF) system includes the fuel racks, NF assemblies, and the

rod cluster control assemblies (including the wet annular burnable absorber) that together

provide and enable control of the nuclear heat source. The fuel and control components

provide a safe and controllable source of power to heat the reactor coolant water. The fuel

racks store new and used fuel that is not in service in the reactor core.

As their primary safety intended function, the fuel and control components provide a barrier for

fission products, a coolable configuration for the NF, and control and shutdown capability for

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the core. The ability to safely shut down the reactor core also supports the Appendix R safeshutdown analysis and the SBO event. Therefore, the NF 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). These components

are not subject to an AMR because they are periodically replaced.

As its primary safety intended function, the fuel racks prevent criticality of the stored fuel.

Section 2.4.2 of the LRA evaluates the fuel racks as structural components in the auxiliary

building.

Refueling. The refueling system performs core alterations and other fuel movements, including

movements within the SFP. The system includes the following:

* fuel transfer system

* upending devices

* refueling cavity manipulator cranes

* new and spent fuel handling crane

* new fuel elevator

* a variety of handling tools

Normal functions of the refueling system do not require inclusion of the system in the scope of

license renewal. However, the system is included because of the potential for spatial

interactions with safety related equipment, which is in accordance with 10 CFR 54.4(a)(2). The

refueling cavity manipulator cranes and the new and spent fuel handling crane require an AMR.

Section 2.4 of the LRA evaluates the cranes as structural components in the structures that

house them.

Residual Heat Removal. For license renewal, LRA Section 2.3.2.3 evaluates the RHR system

as part of the ECCS. The containment spray evaluation in LRA Section 2.3.2.1 includes

portions of the spray header that are supplied by the RHR system.

Reactor Vessel Level Instrumentation. The RVLIS indicates the relative vessel water level or

the relative void content of fluid in the vessel during postaccident conditions. This level

indication assists personnel in recognizing conditions that may lead to damage of the vessel or

the core. Sensors measuring the differential pressure between the vessel head and bottom

and between the head and the hot legs provide the basis for level and void fraction indication.

The safety intended function of the mechanical portions of the system is to maintain the RCPB,

which is in accordance with 10 CFR 54.4(a)(1). Section 2.3.1 of the LRA includes this system

in the review of the RCS.

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 (regarding nuclear fuels, RHR, and reactor vessel

level indication) and CNP UFSAR Chapter 3 and Sections 9.7 and 4.2.11 to determine whether

the applicant identified the miscellaneous systems components within the scope of license

renewal and subject to AMR. 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.

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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 verify 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 within the scope of license renewal to verify that it did not omit any -

passive and long-lived components that should be subject to an AMR in accordance with therequirements of 10 CFR 54.21 (a)(1).

On the basis of its review, the staff found that the applicant identified those portions of the

miscellaneous systems that meet the scoping requirements of 10 CFR 54.4(a) and included

them within the scope of license renewal in LRA Section 2.3.3.12.' The applicant'also included

the miscellaneous systems 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.

2.3.3.12.3 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 SCs of the miscellaneous systems.

Therefore, the staff concludes that the applicant adequately identified the miscellaneous

systems SCs that are within the scope of license renewal, as'required by 10 CFR 54.4(a), and

that the applicant adequately identified the miscellaneous systems SCs that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

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 components of the steam and power conversion systems:

* main feedwater

* main steam

* auxiliary feedwater

* steam generator blowdown

* main turbine

The applicant determined the steam and power conversion systems SSCs that are within the

scope of license renewal as described in the following sections.

2.3.4.1 Main Feedwater

2.3.4.1.1 Summary of Technical Information ih the Application

In Section 2.3.4.1 of 'the LRA, the applicant described the main feedwater system. -The main

feedwater system supplies feedwater to the steam generators at appropriate temperature,

pressure, and flow rates under all steady-state and transient load conditions. 'The main

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feedwater system uses turbine-driven feedwater pumps to supply water from the condensate

system to the steam generators. The main feedwater system includes high-pressure feedwater

heaters to improve plant thermal efficiency by preheating the feedwater.

The main feedwater flowpath from the main feedwater check valves to the steam generators is

safety related. This portion of the system provides an extension of the containment liner and

provides a flowpath for the AFW to the steam generators. In addition to these safety intended

functions, the system also provides ESF actuation system feedwater isolation and feedwater

regulating valve closure when required.

The mechanical function required of the main feedwater system during an SBO event is to

maintain the secondary system pressure boundary from the main feedwater check valves to the

steam generators. The mechanical functions required of the main feedwater system during an

Appendix R safe-shutdown event are to maintain the same portion of the secondary system

pressure boundary and to support AFW addition to the steam generators.

The main feedwater system is also included in the scope of license renewal because of the

potential for spatial interactions with safety related equipment. The main feedwater system

nonsafety related components requiring an AMR pursuant to 10 CFR 54.4(a)(2) are in the

auxiliary building.

Therefore, the main feedwater 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 2.3.4-1 of the LRA, the applicant identified the main feedwater component types that

are within the scope of license renewal and subject to an AMR, including bolting, piping, and

valve.

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 and CNP UFSAR Section 10.5.1 to determine whether

there is reasonable assurance that the applicant identified the main feedwater system

components within the scope of license renewal and subject to an AMR in accordance with

10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff conducted its review in accordance with the

guidance in Section 2.3 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 being within the scope of license

renewal to verify 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's review of LRA Section 2.3.4.1 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. Therefore,

the staff issued RAls to the applicant concerning these specific issues 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's RAls and the applicant's responses are described below.

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RAI 2.3.4.1-1

LRA Section 2.3.4.1 states that the FW system is in the scope of license renewal based on the

potential for spatial interactions with safety-related equipment. License renewal drawings only

show the safety-related portion of the FW system which is within the scope of license renewal

based on the criteria of 10 CFR 54.4(a)(1). The remainder of the FW system is continued on

additional drawings that are not included in the LRA. Therefore, the staff is unable to determine

whether those FW system components that meet 10 CFR 54.4(a)(2) criteria are identified as

component types subject to an AMR in LRA Table 2.3.4-1. The staff asked that the applicant

provide drawings or text information that identifies the FW system components within the scope

of license renewal because they meet the criteria of 10 CFR 54.4(a)(2) as described. If any of

these components which are passive and long-lived are not included as a component type in

LRA Table 2.3.4-1, the applicant was asked to revise this table.

In its response dated May 7, 2004, the applicant stated that nonsafety-related component types

in the feedwater system that require an AMR under 10 CFR 54.4(a)(2) are located in the

auxiliary building and consist of the component types of bolting, orifices, thermowells, valves,

manifolds, tubing, and piping. AMPs for the environment and material combinations identified

in LRA Table 3.4.2-1 will manage aging for the component types listed above. In its responses

to RAI 2.3.3.11-2 dated May 20, 2004, and September 2, 2004, the applicant discussed the

scoping and screening of components meeting the criteria of 10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-1 acceptable

because it adequately addressed the questions concerning the scoping and screening of

components meeting the criteria of 10 CFR 54.4(a)(2) and identified the location of the

nonsafety related portions of the main feedwater system that meet the criteria of

10 CFR 54.4(a)(2). Therefore, the staff's concerns described in RAI 2.3.4.1-1 are resolved.

RAI 2.3.4.1-2

For those SSCs within the scope of license renewal in accordance with 10 CFR 54.4,

10 CFR 54.21 (a)(1) requires the applicant to identify and list those SCs subject to an AMR.

The staff could not determine if the applicant considered all the SSCs within the scope of

license renewal to satisfy this requirement.

Section 2.1.2.1.1 of the LRA states that the identification of components subject to an AMR

begins with the determination of the system evaluation boundary. The system evaluation

boundary includes those portions of the system that are necessary to ensure that the intended

functions of the system will be performed. Components needed to support each of the system-,

level intended functions identified in the scoping process are included within the system

evaluation boundary.

The staff could not verifywhether the applicant identified all the components that perform an

intended function because it did not identify the components within the system evaluation

boundary in its LRA. The staff must verify this information to effectively review the LRA using

the SRP-LR.

The staff asked the applicant to confirm that the system components marked on license

renewal drawings for the main feedwater system depict all the components that perform an

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intended function. If not, the applicant was asked to provide a list of those components that

perform an intended function but are not marked on license renewal drawings, or provide

revised drawings as needed to include the additional components.

In its response dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings indicate all components that perform an intended function, with the

exception of feedwater regulating valves and the feedwater isolation valves that have an active

function of feedwater isolation upon receipt of an ESF actuation system signal. The ESF

actuation system functions of the feedwater isolation and feedwater regulating valve closure

rely on the active function of the motor-operated feedwater isolation valves or the pneumatically

operated feedwater regulating valves. Both sets of valves prevent the supply of feedwater to

the steam generators and do not require pressure boundary integrity of this portion of the

system. If pressure boundary is lost in this portion of the system, interruption of feedwater flow

to the steam generator would occur. Therefore, these feedwater valves and this portion of the

system do not require an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-2 acceptable. The

applicant adequately described the process for identifying system components on license

renewal drawings that are subject to an AMR. The applicant described as necessary the

components that meet the requirements of 10 CFR 54.4(a) but are not shown on the license

renewal drawings and discussed the alteration of the system evaluation boundaries. Therefore,

the staff confirmed that the applicant evaluated all the components with intended functions for

an AMR, including those components at license renewal system boundaries and interfaces with

other systems. The applicant identified as necessary those components within the system

evaluation boundary for a license renewal system that are not subject to an AMR. Therefore,

the staff's concern described in RAI 2.3.4.1-2 is resolved.

RAI 2.3.4.1-3

Section 2.1.2.1.2 of the LRA states that the applicant created the license renewal drawings by

marking mechanical flow diagrams to indicate only those components within the system

evaluation boundaries that require an AMR. Components that are within the scope of license

renewal based solely on the criteria of 10 CFR 54.4(a)(2) are not generally indicated on the

drawings but are described in LRA Section 2.3 and listed in LRA Table 3.3.2-11.

Pursuant to 10 CFR 54.21 (a)(1), the applicant must identify and list those SCs subject to an

AMR. The staff's position is that the applicant had not satisfied this requirement because the

components of the main feedwater system meeting the criteria of 10 CFR 54.4(a)(2) are neither

identified on drawings nor listed. The applicant included the component types instead of

individually listed components. Therefore, the staff asked the applicant to confirm that the main

feedwater system components marked on license renewal drawings depict all the components

within the main feedwater system that meet the criteria of 10 CFR 54.4(a)(2). If not, the

applicant was asked to provide a list of components not marked on license renewal drawings or

provide revised drawings as needed to include the additional components.

In its responses dated May 20, 2004, and September 2, 2004, the applicant confirmed that the

LRA tables group the components meeting the criteria for 10 CFR 54.4(a)(2) as component

types instead of as individual components.

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The applicant's 10 CFR 54.4(a)(2) identification process, as described in the response to RAI

2.3.3.11-2, designates nonsafety-related systems and components with the potential for spray

or leakage that could prevent safety-related systems and components from performing their

required safety functions. Conservatively, the applicant determined all nonsafety-related

components containing liquid or steam located in the auxiliary building and screenhouse to Ube

subject to an AMR unless no safety-related equipment is in the area.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-3 acceptable

because it provided an adequate explanation in its responses to RAI 2.3.3.11-2 about the'

components in the auxiliary building and screenhouse that are subject to an AMR according to

the criteria of 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.4.1-3 is

resolved.

2.3.4.1.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs'of the main' feedwater'system.

Therefore, the staff concludes that the applicant adequately identified the main feedwater

system SCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant adequately identified the main feedwater system SCs that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.2 Main Steam

2.3.4.2.1 Summary of Technical Information in the Application

In Section 2.3.4.2 of the LRA, the applicant described the main steam system. The main steam

system delivers steam from the steam generators to the turbine and to other equipment or'

systems requiring main steam, including the following: -

* turbine driver of an auxiliary feedwater pump

* main feed pump turbines

* reheaters

* 'f turbine bypass system (steam dump)

* auxiliary steam system

* turbine steam seals (Unit 2 only)

The main steam flowpath from the steam generators to the main steam isolation valves is

safety related. This portion of the main steam system provides the primary safety intended

functions, including removing heat from the RCS via the main steam'safety valves to prevent

RCS overpressurization. This portion of the system also provides an extension of the

containment liner and a flowpath to the main steam safety valves, AFW pump turbine, -and

steam generator PORVs --

With the main steam isolation valves closed, the'steam generator PORVs can be used to'

provide a controlled cooldown. In addition to these safety intended functions, the system also

provides containment isolation of the steam sampling lines when required. The controlled

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cooldown function with the steam generator PORVs also supports the Appendix R safeshutdown and SBO events.

The main steam system is also included in the scope of license renewal because of the

potential for spatial interactions with safety related equipment. The nonsafety related

components in the main steam system that require an AMR under 10 CFR 54.4(a)(2) are in the

auxiliary building and the turbine building in the auxiliary feedwater pump rooms.

Therefore, the main steam 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 2.3.4-2 of the LRA, the applicant identified the main steam component types that are

within the scope of license renewal and subject to an AMR, including bolting, manifold (piping), orifice, piping, tubing, and valve.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2 and CNP UFSAR Section 10.2 to determine whether

there is reasonable assurance that the applicant identified the main steam system components within the scope of license renewal and subject to an AMR, in accordance with 10 CFR 54.4

and 10 CFR 54.21(a)(1). The staff used the evaluation methodology described in Section 2.3

of this SER. The staff conducted its review in accordance with the guidance in Section 2.3 of

the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 being within the scope of license

renewal to verify 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's review of the LRA Section 2.3.4.2 identified areas in which additional information

was necessary to complete the review of the applicant's scoping and screening results.

Therefore, the staff issued RAIs to the applicant concerning these specific issues 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's RAIs and the applicant's responses are described

below.

RAI 2.3.4.2- 1

Section 2.3.4.2 of the LRA states the following:

The main steam system is also included in the scope of license renewal due to

the potential for spatial interactions with safety-related equipment. The nonsafety-related components in the main steam system that require aging

management review for 10 CFR 54.4(a)(2) are in the auxiliary building and the

turbine building in the auxiliary feedwater pump rooms.

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Section 2.1.2.1.2 of the LRA states that components within the scope of license renewal based

on the criteria of 10 CFR 54.4(a)(2) are not indicated on the drawings but are described in LRA

Section 2.3 and listed in LRA Table 3.3.2-11.

License renewal drawings LRA-1-5105D, LRA-2-5105D, LRA-1-5141A, and LRA-2-5141A show

the safety-related portion of the main steam system only from the steam generators to the main

steam isolation valves. This portion of the system is within the scope of license renewal based

on the criteria of 10 CFR 54.4(a)(1). License renewal drawing LRA-1 -5105 shows the

nonsafety related portion of the system downstream of the isolation valves up to the

high-pressure turbine. However, the drawing does not highlight any components belonging to

the main steam system. Additionally, LRA Table 3.3.2-11 lists component types under the

general heading of 'Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2)" rather than

associating them with specific systems. As a result, by using this table and the license renewal

drawings provided; the staff could not verify that the applicant properly identified all main steam

system components within the scope of license renewal and subject to an AMR.

Therefore, the staff asked the applicant to clarify whether all the nonsafety-related components

of the main steam system are within the scope of license renewal, because of a potential spatial

interaction with safety-related equipment, and subject to an AMR in accordance with

10 CFR 54.4(a)(2) and 10 CFR 54.21 (a)(1). If not, the applicant was asked to identify which

components are within scope and subject to an AMR.

In its response dated May 7, 2004, the applicant stated that the nonsafety-related component

types in the main steam system that require an AMR pursuant to 10 CFR 54.4(a)(2) are located

in the auxiliary building and inside the AFW pump rooms in the turbine building. They consist of

bolting, tanks, strainers, traps, valves, tubing, and piping. As described in LRA Section

2.3.3.11, the main steam system is a Group 1 system. For systems in Group 1, the material

and environments are the same in the portion of the system meeting the criteria of

10 CFR 54.4(a)(2) as for those portions meeting the criteria of 10 CFR 54.4(a)(1) or

10 CFR 54.4(a)(3). AMPs for the environment and material combinations identified in LRA

Table 3.4.2-2 will manage aging for all the component types listed above.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-1 acceptable

because the applicant identified the location of the nonsafety related portions of the main steam

system that meet the criteria of 10 CFR 54.4(a)(2) and provided the component types subject to

an AMR. Therefore, the staff's concerns described in RAI 2.3.4.2-1 are resolved.

RAI 2.3.4.2-2

License renewal drawings LRA-1 -51 05D and LRA-2-51 05D show the four main steam isolation

valves and their actuators. Section 10.2.2 of the UFSAR describes the design of theseactuators. The drawings show the actuator cylindrical housings as within the scope of license

renewal and subject to an AMR. However,-LRA Table 2.3.4-2 does not specifically list these

housings as a component type subject to an AMR. These housings are passive, long-lived

components and meet the requirements of 10 CFR 54.21 (a)(1) for an AMR. Therefore, the --

staff asked the applicant to clarify whether one of component types listed in LRA Table 2.3.4-2

includes these housings. If not, the staff requested the applicant to justify the exclusion of

these housings from an AMR.

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In its response dated May 7, 2004, the applicant stated that the steam cylinders for the steam

generator stop valves MRV-210, 220, 230, and 240 form part of the main steam pressure

boundary and are an integral part of the valve bodies. The steam cylinders and other portions

of the valve body are highlighted on license renewal drawings. They are included in the AMR

for the main steam system and in the component type "valve."

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-2 acceptable

because the applicant has identified that the steam cylinders for the valves are included in the

AMR for main steam since they are steam-filled pressure boundaries of the main steam

system. Therefore, the staff's concerns described in RAI 2.3.4.2-2 are resolved.

RAI 2.3.4.2-3

For those SSCs within the scope of license renewal in accordance with 10 CFR 54.4,

10 CFR 54.21 (a)(1) requires the applicant to identify and list those SCs subject to an AMR.

The staff could not decide whether the applicant considered all the SSCs within the scope of

license renewal to satisfy this requirement.

Section 2.1.2.1.1 of the LRA states that the identification of components subject to an AMR

begins with the determination of the system evaluation boundary. The system evaluation

boundary includes those portions of the system that are necessary to ensure that the intended

functions of the system will be performed. Components needed to support each of the systemlevel intended functions identified in the scoping process are included within the system

evaluation boundary.

The staff could not verify whether the applicant identified all the components that perform an

intended function because it did not identify the components within the system evaluation

boundary in the LRA. The staff must verify this information to effectively review the LRA using

the SRP-LR.

Therefore, the staff asked the applicant to confirm that the system components marked on the

license renewal drawings for the main steam system depict all the components that perform an

intended function. If not, the applicant was asked to provide a list of those components that

perform an intended function but are not marked on license renewal drawings, or provide

revised drawings as needed to include the additional components.

In its response dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings indicate all components that perform an intended function, with the

exception of structures, active and short-lived components, and those components that are in

scope and subject to an AMR based solely on the criteria of 10 CFR 54.4(a)(2). Active

components that were screened out and not highlighted on flow diagrams are those that do not

meet the 10 CFR 54.21(a)(1)(i) criteria, as identified in Appendix B to NEI 95-10, including

items such as instrumentation, motors, and valve operators.

Marking up the license renewal drawings to show components that are in scope and subject to

an AMR based solely on the criteria of 10 CFR 54.4(a)(2) would be of minimal value, if any,

since such components are included in scope if they are installed in the area of safety related

SSCs. Proximity to safety related SSCs cannot be determined from functional flow diagrams.

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The main steam system license renewal drawings do not depict any short-lived components

that perform a 10 CFR 54.4 intended function.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-3 acceptable

because the applicant adequately identified and described the components. Therefore, the

staff's concerns described in RAI 2.3.4.2-3 are resolved.

RAI 2.3.4.2-4

Section 2.1.2.1.2 of the LRA states that the applicant created the license renewal drawings by

marking mechanical flow diagrams to indicate only those components within the system

evaluation boundaries that require an AMR. Components that are within the scope of license

renewal based solely on the criteria of 10 CFR 54.4(a)(2) are not generally indicated on the

drawings but are described in LRA Section 2.3 and listed in LRA Table 3.3.2-11.

Pursuant to 10 CFR 54.21 (a)(1), the applicant must identify and list those SCs subject to an

AMR. The staff's position is that the applicant did not satisfy this requirement because the

components of the main steam system meeting the criteria of 10 CFR 54.4(a)(2) are neither

identified on drawings nor listed. The applicant included these as component types instead of

individually listed components. Therefore, the staff asked the applicant to confirm that the main

steam system components marked on license renewal drawings depict all the components

within the main steam system that meet the criteria of 10 CFR 54A(a)(2). If not, the applicant -

was asked to provide a list of these components that are not marked on license renewal

drawings or provided revised drawings as needed to include the additional components.

In responses dated May 20, 2004 and September 2, 2004, the applicant stated that the LRA

tables group the components meeting the criteria of 10 CFR 54.4(a)(2) as component types

instead of as individual components.

The applicant's 10 CFR 54.4(a)(2) identification process, as described in response to RAI

2.3.3.11-2, designates nonsafety-related systems and components with the potential for spray

or leakage that could prevent safety-related systems and components from performing their -

required safety function. Conservatively, the applicant determined all nonsafety-related- -

components containing liquid or steam located in the auxiliary building and screenhouse to be

subject to an AMR unless no safety-related equipment is in the area.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-4 acceptable,

because it provided an adequate explanation in its responses to RAI 2.3.3.11-2 about the

components in the auxiliary building and screenhouse that are subject to an AMR under the

criteria of 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.4.2-4 is

resolved.

2.3.4.2.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the main steam system.

Therefore, the staff concludes that the applicant adequately identified the main steam system

SCs that are within the scope of license renewal,-as required by 10 CFR 54.4(a), and that the

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applicant adequately identified the main steam system SCs that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.4.3 Auxiliary 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 AFW system. The AFW system provides feedwater to the steam generators when the main feedwater supply is not available.

The system is the safety related source of feedwater for cooling as required during DBEs. The

system also provides feedwater as required for the SBO and FP regulated events.

Installed in each unit is one turbine-driven AFW pump, which feeds all four steam generators, and two motor-driven AFW pumps, each of which feeds two steam generators. Train

orientation is maintained throughout the AFW system, including the AFW pumps, all associated

valves, instrumentation, and controls. The CST normally provides the water for the AFW

pumps. The ESW system serves as an emergency water source. The motor-driven AFW

pumps can supply the corresponding sets of steam generators in the opposite unit through manual cross-tie supply valves.

Therefore, the AFW 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 2.3.4-3 of the LRA, the applicant identified the AFW component types that are within

the scope of license renewal and subject to an AMR, including bolting, fittings, governor housing, heat exchanger (shell), heat exchanger (tubes), manifold (piping), orifice, piping, pump casing, sight glass, sight glass housing, strainer housing, tank, tubing, turbine casing, and

valve.

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3 and CNP UFSAR Section 10.5.2 to determine whether

there is reasonable assurance that the applicant identified the AFW system components within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21(a)(1). The staff conducted its review in accordance with the SRP-LR, Section

2.3 guidance.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 being within the scope of license

renewal to verify 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's review of LRA Section 2.3.4.3 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. Therefore, the staff issued RAls to the applicant concerning these specific issues 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's RAls and the applicant's responses are described below.

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RAI 2.3.4.3-1

Section 2.3.4.3 of the LRA states, "The floating head seal and associated support posts are

included in the AMR because the failure of the seal could cause flow blockage." License '-

renewal drawings LRA-1-51 06A and LRA-2-51 06A show the CSTs for Units 1 -and 2 as subject

to an AMR. However, both of these drawings show the floating head seal to be excluded from'

an AMR, and LRA Table 2.3.4-3 does not list it as a component type subject to an AMR.

Therefore, the staff asked the applicant to explain why the floating head seal on the CST,

although stated earlier to be subject to an AMR, is not highlighted on the license renewal

drawings nor listed in Table 2.3.4-3 as a component type subject to an AMR. -

In its response dated May 7, 2004, the applicant stated that the floating head seal and

associated support posts are included in the AMR because the failure of the seal could cause

flow blockage. Since the seal does not have a unique component number in the database, LRA

Table 2.3.4-3 includes it in the component type "tank.". As listed in LRA Table 3.4.2-3 under the

component type 'tank," elastomer tank components may experience change in material

properties or cracking. It is an administrative oversight that license renewal drawings

LRA-1 -51 06A and LRA-2-51 06A do not highlight the seals to show that they are subject to an

AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-1 acceptable

because the applicant identified where the LRA tables identify the condensate tank floating

head seal and described it as subject to an AMR. Therefore, the staff's concerns described in

RAI 2.3.4.3-1 are resolved.

RAI 2.3.4.3-2

License renewal drawings LRA-1-5106A and LRA-2-5106A show strainers upstream of the

three AFW pumps. Table 2.3.4-3 of the LRA includes strainer housings as a component type

subject to an AMR; however, this table does not list strainer internals. Failure of the strainer

internals could prevent the strainer from performing its intended function, or possibly cause a

flow blockage. Therefore, the staff asked the applicant to clarify whether these strainer

internals are long-lived and passive. If so, the applicant should justify why Table 2.3.4-3 does

not include the strainer internals as subject to an AMR in accordance with 10 CFR 54.21 (a)(1).

In its response dated May 7, 2004, the applicant stated that strainers upstream of the AFW

pumps have a component intended function of filtration. They are long-lived, passive, and

subject to an AMR. The applicant inadvertently omitted the strainer internals from LRA Tables

2.3.4-3 and 3.4.2-3. The stainless steel strainer internals are submerged in treated water in

AFW pump suction piping, which is the same environment as the stainless steel AFW suction

piping. The AERM is a loss of material, which is managed by the Primary and Secondary

Water Chemistry Control Program. Table 3.4.2-3 of the LRA should include the entry, -

"Component Type-Strainer internals, Intended Function-Filtration, Material-Stainless steel,

Environment-Treated water (internal), Aging Effect Requiring Management-Loss of material,

Aging Management Programs-Water Chemistry. Control." -

Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-2 acceptable

because the AFW pump strainer internals are now included in the appropriate LRA tables and

are subject to an AMR. Therefore, the staff's concerns described in RAI 2.3.4.3-2 are resolved.

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RAI 2.3.4.3-3

License renewal drawing LRA-1 -51 06A shows turbine oil cooler HE-70 and governor oil cooler

HE-71 as within scope and subject to an AMR. Table 2.3.4-3 of the LRA lists the heat

exchanger subcomponents ushell' and 'tubes" as separate component types subject to an

AMR. However, the LRA table does not list the other subcomponents of the lubricating oil

coolers, such as tubesheets and channel heads. Furthermore, license renewal drawing LRA-1-

5106A does not identify the cooling water system used to cool the lubricating oil. Therefore, the

staff asked the applicant to identify the coolers' cooling water system and justify why it does not

consider other heat exchanger internal subcomponents such as tubesheets and channel heads

to be subject to an AMR, or to revise Table 2.3.4-3 to include these items.

In its response dated May 7, 2004, the applicant stated that the turbine oil cooler and governor oil cooler use water from the AFW system itself for cooling. The turbine-driven AFW pump discharge is diverted to flow through the turbine oil cooler and governor oil cooler.

Subcomponents of the lubricating oil coolers, such as tubesheets and channel heads, are

subject to an AMR but are not listed in LRA Table 2.3.4-3. The AMPs that apply to the shell

and tubes also apply to the subcomponents included in the component types "heat exchanger (shell)" and "heat exchanger (tubes)" in LRA Table 2.3.4-3.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-3 acceptable

because it clarifies the cooling medium for the coolers. In addition, the LRA table represents the component types that describe the cooler subcomponents. Therefore, the staff's concerns

described in RAI 2.3.4.3-3 are resolved.

RAI 2.3.4.3-4

For those SSCs within the scope of license renewal in accordance with 10 CFR 54.4,

10 CFR 54.21 (a)(1) requires the applicant to identify and list those SCs subject to an AMR.

The staff could not determine whether the applicant considered all the SSCs within the scope of

license renewal to satisfy this requirement.

Section 2.1.2.1.1 of the LRA states that the identification of components subject to an AMR

begins with the determination of the system evaluation boundary. The system evaluation

boundary includes those portions of the system that are necessary to ensure that the intended

functions of the system will be performed. Components needed to support each of the system- level intended functions identified in the scoping process are included within the system evaluation boundary.

The staff could not verify whether the applicant identified all the components that perform an

intended function because it did not identify the components within the system evaluation

boundary in the LRA. The staff must verify this information to effectively review the LRA using the SRP-LR.

Therefore, the staff asked the applicant to confirm that the system components marked on

license renewal drawings for the AFW system depict all the components that perform an

intended function. If not, the applicant was asked to provide a list of those components that

perform an intended function but are not marked on license renewal drawings, or to provide revised drawings as needed to include the additional components.

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In its response dated May 20, 2004, the applicant stated that system components highlightedon license renewal drawings indicate all components that perform an intended function, with the

exception of structures, active and short-lived components, and those components that are in

scope and subject to an AMR based solely on the criteria of 10 CFR 54.4(a)(2). Active

components that were screened out and not highlighted on flow diagrams are those that do not

meet the 10 CFR 54.21 (a)(1 )(i) criteria, as identified in Appendix B to NEI 95-10, including

items such as instrumentation, motors, and valve operators.

The AFW system license renewal drawings do not depict any short-lived components that

perform a 10 CFR 54.4 intended function.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-4 acceptable,

because it adequately identifies and describes the components. Therefore, the staff's concerns

described in RAI 2.3.4.3-4 are resolved.

2.3.4.3.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensingbasis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the AFW system. Therefore, the

staff concludes that the applicant adequately identified the AFW system SCs that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

identified the AFW system SCs that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.4 Steam Generator Blowdown

2.3.4.4.1 Summary of Technical Information in the Application

In Section 2.3.4.4 of the LRA, the applicant described the steam generator blowdown (SGBD)

system. The SGBD system maintains the proper water chemistry within the steam generators

on the secondary side. The system has a safety intended function of blowdown isolation for

AFW flow conservation and automatic isolation capability. The portion of the SGBD system in

the containment fulfills the safety function of providing an extension of the containment liner.

The system is required to maintain the secondary system pressure boundary for Appendix R

safe-shutdown and SBO events. Some portions of the SGBD system have the potential for

spatial interaction with other safety related equipment.

SGBD is routed to the startup blowdown flash tank during startup or under abnormal operating

conditions, such as during high condenser in-leakage. The steam produced in the startup

blowdown flash tank is vented to the atmosphere through a moisture separator. The water is -

routed to the screenhouse forebay. When the plant reaches normal full-power operation, the

startup blowdown flash tank is taken out of service and the blowdown is routed to the normalblowdown flash tank. The steam from the normal blowdown flash tank is returned to the

condensate system through the condensers, and the water is routed to the screenhouse

forebay either directly or through mixed-bed demineralizers.

Therefore,-the blowdown 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).

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In Table 2.3.4-4 of the LRA, the applicant identified the SGBD component types that are within

the scope of license renewal and subject to an AMR, including bolting, orifice, piping, tubing,

and valve.

2.3.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.4 and CNP UFSAR Section 10.11 to determine whether

there is reasonable assurance that the applicant has identified the SGBD system components

within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1). The staff conducted its review in accordance with the SRP-LR, Section

2.3 guidance.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 being within the scope of license

renewal to verify 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's review of LRA Section 2.3.4.4 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. Therefore,

the staff issued RAls to the applicant concerning these specific issues 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's RAls and the applicant's responses are described below.

RAI 2.3.4.4- I

Section 10.11.2 of the UFSAR states that the SGBD is monitored for radioactivity before

reaching either the startup or normal blowdown flash tanks. These radiation monitors close the

SGBD system isolation valves upon detection of high radioactivity. However, the staff

examined the license renewal drawings for Units 1 and 2 referenced in LRA Section 2.3.4.4 and

could not locate radiation monitors upstream of the flash tanks. Therefore, the staff asked the

applicant to provide information to locate the radiation monitors and to verify whether pressure

boundary retaining housings for these components are subject to an AMR. If not, the applicant

was asked to justify the exclusion of these radiation monitors from an AMR, or to revise Table

2.3.4-4 to include these items.

In its response dated May 7, 2004, the applicant stated that, in each unit, monitor DRA-300

(R-1 9) provides radiation monitoring upstream of the SGBD flash tanks. As shown on license

renewal drawings, the individual steam generator sample valves are upstream of the flash

tanks. The steam generator samples pass through steam generator sample isolation valves

before reaching monitor DRA-300. Radiation monitors 1-DRA-300 and 2-DA-300 do not

support a containment isolation function. The SGBD isolation valves are intended for

equipment protection, as described in UFSAR Section 5.4.1 under containment isolation system

Class F piping, and are not considered containment isolation valves. The closure of these

valves upon a high radiation signal provided by the radiation monitors isolates an effluent

process flow when high steam generator radioactivity exists. Radiation monitors 1 -DRA-300

and 2-DRA-300 pressure retaining boundaries are not subject to aging management since they

are located downstream of the seismic Class 1 break at air-operated fail-closed isolation valves

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DCR-301, DCR-302, DCR-303, and DCR-304. The radiation monitors are outside of the

10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(3) pressure boundary as shown on license renewal

drawings LRA-1-5141A and LRA-2-5141A. Therefore, the radiation monitors are not subject to

an AMR and are not included in LRA Table 2.3.4-4.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-1 acceptable,

because it adequately explained that the radiation monitors are not included within the system

evaluation boundary and are therefore not within the scope of license renewal. Therefore, the

staff's concerns described in RAI 2.3.4.4-1 are resolved.

RAI 2.3.4.4-2

For those SSCs within the scope of license renewal in accordance with 10 CFR 54.4, -

10 CFR 54.21 (a)(1) requires the applicant to identify and list those SCs subject to an AMR.

The staff could not determine whether the applicant considered all the SSCs within the scope of

license renewal to satisfy this requirement.

Section 2.1.2.1.1 of the LRA states that the identification of components subject to an AMR

begins with the determination of the system evaluation boundary. The system evaluation '

boundary includes those portions of the system that are necessary to ensure that the intended

functions of the system will be performed. Components needed to support each of the systerm-_

level intended functions identified in the scoping process are included within the system

evaluation boundary.

The staff could not verify whether the applicant identified all the components that perform an

intended function because it did not identify the components within the system evaluation

boundary in the LRA. The staff must verify this information to effectively review the LRA using

the SRP-LR.

Therefore, the staff asked the applicant to confirm that the system components marked on

license renewal drawings for the SGBD system depict all the components that perform an

intended function. If not, the applicant was asked to provide a list of those components that

perform an intended function but are not marked on license renewal drawings, or provide

revised drawings as needed to include the additional components.

In its response dated May 20, 2004, the applicant stated that system components highlighted

on license renewal drawings include all components that perform an intended function, with the

exception of structures, active and short-lived components, and those components that are in

scope and subject to an AMR based solely on the criteria of 10 CFR 54.4(a)(2). Active

components that were screened out and not highlighted on flow diagrams are those that do not

meet the 10 CFR 54.21 (a)(1 )(i) criteria, as identified in Appendix B to NEI 95-10, including

items such as instrumentation, motors, and valve operators.

Marking up the license renewal drawings to show components that are within scope and subject

to an AMR based solely on the criteria of 10 CFR 54.4(a)(2) would be of minimal value, if any,

since such components are included if they are installed in the area of safety related SSCs, and

proximity to safety related SSCs cannot be determined from functional flow diagrams. The

applicant's response to RAI 2.3.3.11-1 provides a list of SGBD component types that perform

10 CFR 54.4(a)(2) intended function.

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The SGBD license renewal drawings do not depict any short-lived components that perform a

10 CFR 54.4 intended function.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-2 acceptable,

because it adequately identified and described the components. Therefore, the staff's concerns

described in RAI 2.3.4.4-2 are resolved.

RAI 2.3.4.4-3

Section 2.1.2.1.2 of the LRA states that the applicant created the license renewal drawings by

marking mechanical flow diagrams to indicate only those components within the system

evaluation boundaries that require an AMR. Components that are within the scope of license

renewal based solely on the criteria of 10 CFR 54.4(a)(2) are not generally indicated on the

drawings but are described in LRA Section 2.3 and listed in LRA Table 3.3.2-11.

Pursuant to 10 CFR 54.21 (a)(1), the applicant must identify and list those SCs subject to an

AMR. The staff's position is that the applicant failed to met this requirement because the

components of the SGBD system meeting the criteria of 10 CFR 54.4(a)(2) are neither

identified on drawings nor listed. The applicant included these as component types instead of

individually listed components. Therefore, the staff asked the applicant to confirm that the

SGBD system components marked on license renewal drawings depict all the components

within the SGBD system that meet the criteria of 10 CFR 54.4(a)(2). If not, the applicant should

provide a list of these components that are not marked on license renewal drawings or provide

revised drawings as needed to include the additional components.

In its responses dated May 20 and September 2, 2004, the applicant stated that LRA tables

group the components meeting the criteria for 10 CFR 54.4(a)(2) as component types instead

of as individual components.

The 10 CFR 54.4(a)(2) identification process, as described in response to RAI 2.3.3.11-2,

designates nonsafety-related systems and components with the potential for spray or leakage

that could prevent safety-related systems and components from performing their required

safety function. Conservatively, the applicant determined all nonsafety-related components

containing liquid or steam located in the auxiliary building and screenhouse to be subject to an

AMR unless no safety-related equipment is in the area.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-3 acceptable

because it provided an adequate explanation in the responses to RAI 2.3.3.11-2 regarding the

components in the auxiliary building and screenhouse that are subject to an AMR based on the

criteria of 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.4.4-3 is

resolved.

2.3.4.4.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI response, the staff did not identify any omissions or discrepancies in

the applicant's scoping and screening results for the SCs of the SGBD system. Therefore, the

staff concludes that the applicant adequately identified the SGBD system SCs that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

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identified the SGBD system SCs that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.4.5 Main Turbine

2.3.4.5.1 Summary of Technical Information in the Application

In Section 2.3.4.5 of the LRA, the applicant described the main turbine (MT) system. -The MT

generator converts the thermal energy of steam into mechanical shaft power used to rotate the

generator field. The MT system includes the MT and the following supporting systems:,

main turbine lubricating oil

* main turbine lubricating oil cleanup

* main turbine steam seals

* .turbine controls

* electrohydraulic controls

* turbine supervisory instruments

The capability to trip the MT is a required function in support of the ATWS and SBO events.

This is the only intended function of the mechanical components of the MT.

Therefore, the MT is within the scope of license renewal based on the criteria of

10 CFR 54.4(a)(3).

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 and CNP UFSAR Section 10.3.1 to determine whether

there is reasonable assurance that the applicant identified the MT system components within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1).. The staff conducted its review in accordance with the SRP-LR, Section

2.3 guidance.

In conducting its review, the staff evaluated the system functions described in the LRA and

UFSAR to verify 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 being within the scope of license

renewal to verify 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's review of the LRA Section 2.3.4.5 identified areas in which additional information

was necessary to complete the review of the applicant's scoping and screening results.

Therefore, the staff issued RAls to the applicant concerning these specific issues 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's RAls and the applicant's responses are described

below.

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RAI 2.3.4.5-1

Section 2.3.4.5 of the LRA states that the only intended function of the mechanical components

of the MT system is to effect a turbine trip in response to an ATWS or SBO event. Since a

pressure boundary failure of the mechanical components of the control system will

automatically cause a trip, the pressure boundary intended function of these components is not

required following these events. Section 2.3.4.5 of the LRA also states that no passive

mechanical component of the MT system is subject to an AMR.

In accordance with the criteria of 10 CFR 54.4(a)(3), the mechanical components of the MT

control system should be within the scope of license renewal. Since LRA Section 2.3.4.5 does

not reference or provide any boundary drawings that show these components, the staff could

not determine whether the applicant identified all components that should be subject to an

AMR. Therefore, the staff asked the applicant to provide a drawing or a text description of the

MT system to identify the mechanical components of the turbine control system that are subject

to an AMR.

In its response dated May 7, 2004, the applicant stated that the intended function of the

mechanical components of the MT system is to effect a turbine trip in response to an ATWS or

SBO event. In accordance with the criteria of 10 CFR 54.4(a)(3), the turbine control system is

within the scope of license renewal. The turbine control system is a hydraulic system that trips

the turbine by dumping hydraulic fluid from the turbine control valve actuators. Since a

pressure boundary failure of the mechanical components of the control system will

automatically cause a trip, the pressure boundary of these components is not required to

support the system intended function. Mechanical components that actually dump the hydraulic

fluid are active and do not require an AMR. Since passive mechanical components have no

intended function, they also require no AMR. Therefore, no mechanical components of the

turbine control system are subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.5-1 acceptable

because it explains that the MT system has no passive components within the scope of license

renewal; thus, no AMR is required. Therefore, the staff's concerns described in RAI 2.3.4.5-1

are resolved.

2.3.4.5.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI response, the staff did not identify any omissions or discrepancies in

the applicant's scoping and screening results for the SCs of the MT system. Therefore, the

staff concludes that the applicant adequately identified the MT system SCs that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

identified the MT system SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4 Scoping and Screening Results-Structures

This section documents the staff's review of the applicant's scoping and screening results for

structures. Specifically, this section discusses the following structures:

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* containment

* auxiliary building

* turbine building and screenhouse

* yard structures

* structural commodities

In accordance with the requirements stated in 10 CFR 54.21 (a)(1), the applicant must identify

and list passive, long-lived structures and structural components that are within the scope of

license renewal and subject to an AMR. To verify that the applicant properly implemented its

methodology, the staff focused its review on the implementation results. This approach allowed

the staff to confirm that the applicant did not omit any structures and structural components that

meet the scoping criteria and are subject to an AMR.

The staff performed its evaluation of the information provided in the LRA in the same manner

for all SCs. The review sought to determine if the applicant identified the components and - .- supporting structures for a specific containment, structure, or containment support that appear

to meet the scoping criteria specified in 10 CFR Part 54 as within the scope of license renewal

in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results

to verify that all long-lived, passive components are subject to an AMR in accordance with

10 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 have not been identified as within

the scope of renewal. The staff reviewed relevant licensing basis documents, including the

UFSAR, for each structure or structural component to determine whether the applicant 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 whether

the LRA specifies all intended functions delineated under 10 CFR 54.4(a). If the staff identified

any omissions, it 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 whether the

functions 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

10 CFR 54.21(a)(1). For those that do not meet either of these criteria, the staff sought to

confirm that these structures and structural components are subject to an AMR, as required by

10 CFR 54.21(a)(1). If the staff identified discrepancies, it requested additional information to

resolve them.

In LRA Table 2.2-3, the applicant identified the following structures as within the scope of

license renewal:

* containment (LRA Section 2.4.1)

* ,-auxiliary building (LRA Section 2.4.2)-

* -turbine building and screenhouse (LRA Section 2.4.3)

* - yard structures (LRA Section 2.4.4) -- fire protection pump house:

- flood protection earth (under roadway)

- gas bottle storage tank foundation

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.

- roadway

- security diesel generator room

- switchyard control house

- tank area pipe tunnel (condensate storage tank, refueling water storage tank,

and emergency diesel generator piping tunnel) - tank foundations (condensate storage tank)

- tank foundations (FP water storage tank)

- tank foundations (primary water storage tank) - tank foundations (refueling water storage tank)

- tower (Unit 1 power delivery to switchyard)

- tower (Unit 2 power delivery to switchyard)

- transformer pedestals

- trench from switchyard to startup transformers (duct bank)

Although not listed in LRA Table 2.2-3, the applicant also defined a structural commodities

group in LRA Section 2.4.5.

Sections 2.4.1, 2.4.2, 2.4.3, 2.4.4, and 2.4.5 of the LRA, and the associated LRA Tables 2.4-1,

2.4-2, 2.4-3, 2.4-4, and 2.4-5, provide the detailed lists of structures and structural components

included in each of these five groups.

RAI 2.4-1

In LRA Table 2.2-4, the applicant identified structures that are not within the scope of license

renewal. Based on its review of this table, the staff requested the following additional

information related to scoping in RAI 2.4-1:

(a) LRA Table 2.2-4 identifies structures that are not within the scope of license

renewal. The note at the top of the table states 'The UFSAR does not contain

details of these structures." It is not obvious to the staff that all of the listed

structures serve no intended function. Please provide (1) a description of the

containment access building, gas cylinder storage building, hazardous storage

building, and the loop feed enclosure; and (2) the technical basis for the

determination that they are not within the scope of license renewal.

(b) LRA Table 2.2-4 identifies the "Switchyard tower and pedestal for Unit 2 power

delivery" as not being within the scope of license renewal. However, LRA Table

2.2-3 and LRA Section 2.4.4 "Yard Structures" identify "Tower: Unit 2 power

delivery to switchyard" as within scope and subject to aging management review.

Please resolve this apparent discrepancy.

(c) Verify that seismic 11/I considerations are not applicable to any of the structures

listed in LRA Table 2.2-4 (i.e., meteorological and microwave towers).

(d) Verify that there is no site drainage or dewatering system that is relied on to

control the groundwater level. If there is such a system, describe it and identify

whether it is within the scope of license renewal. Provide the technical basis for

either including it in or excluding it from the scope of license renewal. If within

the scope, identify the applicable AMR references in LRA Section 3.

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By letter dated May 7, 2004, the applicant submitted the following response to RAI 2.4-1:

(a) The containment access building, gas cylinder storage building, and the

hazardous storage building do not perform intended functions. The

containment access building is located east of the auxiliary building crane

bay. It houses the offices for the Radiation Protecti6n Departrfient and

serves as the primary entry/exit point for the radiologically restricted area.

The gas cylinder storage building stores miscellaneous gas cylinders and

is located on grade south of the Unit 2 turbine building: The hazardousstorage building is'a modular building, located west of the Unit 1 turbine

building, in which 55-gallon drums of chemical waste are stored;

These three structures are not connected to seismic structures and do

not provide:

(1) structural support or functional support for safety related

(2) equipment;

'(2) shelter or protection for safety related equipment;

(3) structural or functional support for non-safety related equipment

whose failure could directly prevent satisfactory accomplishment

of required safety related functions;

(4) missile barriers (internally or externally generated);

(5) flood protection barriers (internal or external flooding event);

(6) rated fire barriers to confine or retard a fire from spreading to or

from adjacent regulatory fire areas or regulatory fire zones; or

(7) structural or functional support for components credited for

regulated events.

Note that the "Gas bottle storage tank foundation" listed in

LRA Table 2.2-3, the "Gas bottle storage tank rack" listed in

LRA Table 2.4-4, and the "Gas bottle storage tank rack and foundation"

listed in LRA Section 2.4.4 refer to the nitrogen bulk storage tank

foundation and racks, which is in scope for 10 CFR 54.4(a)(3)

requirements, and not to the-gas-cylinder storage building discussed

above.

The inclusion of the loop feed enclosure in LRA Table 2.2-4 is an error.

The loop feed enclosure is in the scope of license renewal as part of the

offsite power (OFPW) system (which was included based on NRC

guidance pertaining to station blackout).:The OFPW system provides the

electrical interconnections between the offsite network and the station

auxiliary buses, as well as electrical interconnections among other -

buildings and facilities located on the CNP site: The concrete portion of

the loop feed enclosure is covered in LRA Table 2.4-4, under line item

'Trench from switchyard to start-up transformers (duct bank)." The

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enclosure itself is covered in LRA Table 2.4-5 under line item "Electrical

instrument panels and enclosures."

(b) The inclusion of "Switchyard tower and pedestal for Unit 2 power delivery"

in LRA Table 2.2-4 is an administrative error. The same item is correctly

identified in LRA Table 2.2-3.

(c) During the scoping process, Seismic 11 over I considerations were verified

as not applicable to structures that were correctly listed in LRA Table

2.2-4, including meteorological and microwave towers.

(d) CNP does not have any site drainage or dewatering system that is relied

on to control the groundwater level.

The staff reviewed the applicant's response and found that it provides an adequate technical

basis for the applicant's scoping determinations. In response to part (a) of the RAI, the

applicant provided adequate justification that the containment access building, gas cylinder

storage building, and hazardous storage building are not within the scope of license renewal.

The applicant indicated that the loop feed enclosure is within scope and is listed in LRA Table

2.2-4 in error. In response to part (b) of the RAI, the applicant acknowledged that the

"Switchyard tower and pedestal for Unit 2 power delivery" is within scope and is listed in LRA

Table 2.2-4 in error. In response to part (c) of the RAI, the applicant verified that seismic 11/1

considerations do not apply to structures correctly listed in LRA Table 2.2-4. (The loop feed

enclosure and "Switchyard tower and pedestal for Unit 2 power delivery" do not belong in the

table.) In response to part (d) of the RAI, the applicant verified that there is no system relied on

to control the ground water level. Therefore, the staff's concerns described in RAI 2;4-1 are

resolved.

RAI 2.4-4

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 CNP scoping, screening, and AMR results for load handling systems, the staff requested

the following additional information related to scoping of load handling systems in RAI 2.4-4:

It is not clear to the staff about the scope of load handling systems included in

the D.C. Cook license renewal scope. LRA Section 2.3.3.12,

"Material/Equipment Handling" and "Refueling", identify specific cranes that are

in the scope of license renewal, and refer to LRA Section 2.4 for the evaluation.

LRA Sections 2.4.1, 2.4.2, 2.4.3, and 2.4.5 all identify load handling systems

under "Evaluation Boundaries" and/or in the associated Table 2.4-x. However,

there is not a one-to-one correspondence between all of the cranes listed in

LRA Section 2.3.3.12 and the information in LRA Section 2.4. Also, it is not clear

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if there are additional load handling systems in the LR scope and covered by

LRA Section 2.4.

With the concerns stated'above, the applicant is requested to: (1) provide a

listing of all load handling systems in the LR scope; (2) identify specific

components that are subject to an AMR, for each in-scope load handling system;

(3) identify the specific line item in LRA Tables 2.4-1, 2.4-2, or 2.4-5 that covers

each component; and (4) identify the applicable AMR reference for each

component.

By letter dated May 7, 2004, the applicant submitted the following response to RAI 2.4-4:

(1) LRA Section 2.3.3.12 provides a general description of the material

handling system and provides a reference to LRA Section 2.4 for cranes'

that are evaluated as structural components. Load handling systems that

perform an intended function for license renewal are:

* Ice condenser equipment access end wall cranes

* Ice condenser bridge cranes

* Polar cranes

* Auxiliary building cranes

* Spent fuel cranes

* Emergency diesel generator cranes

* Auxiliary building hoists:

- Motor driven and turbine driven auxiliary feed pump room

manual hoists

- Reactor coolant filter and seal water return filter hoists

Concentrates, seal water injection, and ion exchange

filters hoists

- Reciprocating charging pump room hoists

- Centrifugal charging pump room hoists

- Safety injection pump room hoists

- Containment spray pump room hoists

- Residual heat removal pump room hoists

- Main steam stop enclosure hoists

Recirculation valve enclosure hoists

(2) Crane rails, girders, and their associated supports and anchorages are

subject to aging management review for all in-scope load handling

systems.

(3) The following table provides the cross-reference to specific line items in

LRA tables.

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Load Handling System

Ice condenser equipment

access end wall cranes

Ice condenser bridge

cranes

Polar cranes

Auxiliary building cranes

Spent fuel cranes

Emergency diesel

generator cranes

Auxiliary building hoists

listed in response to subpart (1) of this question

LRA Table Cross Reference

Table 2.4-1 and

Table 3.5.2-1

Table 2.4-1 and

Table 3.5.2-1

Table 2.4-1 and

Table 3.5.2-1

Table 2.4-2 and

Table 3.5.2-2

Table 2.4-2 and

Table 3.5.2-2

Table 2.4-2 and

Table 3.5.2-2

Table 2.4-5 and

Table 3.5.2-5

Table Line Item

Ice condenser

bridge cranes,

crane rails, and

supports

Ice condenser

bridge cranes,

crane rails, and

supports

Polar cranes,

crane rails, and

supports

Cranes, rails,

and supports

Cranes, rails,

and supports

Cranes, rails,

and supports

Cranes, rails,

and girders

(4) The applicable aging management review reference in the LRA for each

component is shown in the LRA Section 3 tables listed in sub-part (3) of

this question.

The staff reviewed the applicant's initial response and found that it adequately describes the

scoping, screening, and AMR for load handling systems, with one exception. In telephone

conference calls with the applicant held on May 17, 2004, and May 21, 2004, the staff

requested that the applicant submit supplemental information to clarify the crane active and

passive components. The applicant stated that the crane itself is an active component. All

other components (i.e. rail, girders) are passive parts. The applicant submitted the following

supplemental response to RAI 2.4-4, by letter dated August 11, 2004:

The applicant's original response to paragraph (2) of RAI 2.4-4, provided in the

May 7, 2004, RAI response letter, ...identified some of the load handling system

components that are subject to aging management review. This supplemental

response provides clarification to the original RAI 2.4-4 response by revising and

expanding paragraph (2) of the original RAI 2.4-4 response to clearly identify the

in-scope load handling system structural components that perform a license

renewal intended function:

(2) The structural components (including crane rails, girders, bridge, trolley,

monorails, and their associated supports and anchorages) of the in-scope

load handling systems are subject to aging management review.

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The staff reviewed the applicant's supplemental response and finds that it adequately identifies

the passive components of cranes that are within scope and subject to an AMR. Therefore, the

staff's concerns described in RAI 2.4-4 are resolved.

2.4.1 Containment

2.4.1.1 Summary of Technical Information in the Application

In Section 2.4.1 of the LRA, the applicant identified the SCs of the containment that are subject

to an AMR for license renewal. The containment structure serves as both a biological shield

and a pressure container during a LOCA or steamline break accident: The containment

structure, including all penetrations and the interior structure, is part of the ESF incorporated in

the design of CNP and is classified as a safety related, seismic Class I structure. CNP Units 1

and 2 use ice condenser reactor containment systems. The containment building is a

reinforced concrete structure consisting of a vertical cylinder, a hemispherical dome, and a flat

base slab. A steel liner is attached to the inside face of the concrete (shell, dome, and the base

slab) to ensure a high degree of leak tightness. The interior of the containment structure is

divided into three compartments:

(1) a lower compartment that houses the reactor and the RCS

(2) an intermediate compartment that houses the energy absorbing ice bed (ice condenser

compartment)

(3) an upper, compartment that accommodates the air displaced from the other two

compartment volumes during an accident condition

The ice condenser is essentially a well-insulated cold storage room that maintains ice in an

array of vertical cylindrical columns. The ice columns are formed by perforated sheet metal

baskets of ice, with the space between columns forming the flow channels for steam and air.

The ice condenser is contained in the annulus formed by the containment vessel wall and the

crane wall, circumferentially over a 300-degree arc. The refueling canal and equipment hatch

are located in the remaining 60-degree arc. The ice condenser compartment extends from

below the operating deck to the top of the crane wall. The uppermost section of the ice

condenser forms a plenum, which accommodates the air cooling equipment and provides

access for ice loading and maintenance. A small bridge crane is provided at the top of the ice

condenser compartment for construction and maintenance purposes.

In the event of an accident, lower inlet doors located below the operating deck at the bottom of

the ice condenser open because of the pressure rise in the lower compartment. This allows

steam to flow from the lower compartment into the ice condenser compartment. The steam is

condensed as it enters the ice condenser compartment, thus limiting the peak pressure in the

containment. (The condensation of steam in the ice bed limits the containment pressure to a

value substantially lower than that of a comparable dry-type containment under the same

conditions.) Upon pressure increase in the ice compartment, the intermediate and top doors in

the ice condenser compartment open to allow air to flow into the upper compartment. Seals are

provided on the boundary of the lower and upper compartments and on the hatches in the

operating deck to limit steam bypassing the ice condenser.

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The primary safety intended function of the containment is to limit the release of radioactive

fission products following an accident, thereby limiting the dose to the public and control room

operators. The containment structure also provides physical support for itself, the RCS, ESF,

and other systems and equipment located within the structure. The exterior walls and dome

provide protection for the reactor vessel and all other safety related SSCs inside the

containment from missiles (internal and external) and natural phenomena.

The containment includes nonsafety related commodity groups that must maintain mechanical

and structural integrity so that nearby safety related equipment is not adversely affected. The

containment also supports, protects, and provides penetrations for safe-shutdown equipment

required under Appendix R to 10 CFR Part 50, environmentally qualified electrical equipment,

and equipment used to cope with an SBO.

Therefore, the containment 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 2.4-1 of the LRA, the applicant identified the containment component types that are

within the scope of license renewal and subject to an AMR. Those made of steel include air

lock doors; air lock hinges, locks, and closing mechanisms; containment liner and associated

anchorage; containment penetrations (mechanical and electrical); CRDM support structure;

divider barrier access doors and associated framing; divider barrier equipment hatches and

associated framing; fuel transfer tube penetration; ice baskets; ice condenser bridge cranes,

crane rails, and supports; ice condenser intermediate deck door frames; ice condenser lattice

frame; ice condenser lower deck door frames; ice condenser lower support structure; ice

condenser turning vanes; ice condenser wall duct panels; polar cranes, crane rails, and

supports; pressurizer supports; reactor cavity missile block embedded steel and associated

framing; RCP supports; reactor vessel supports; removable gate (bulkhead); seal table; steam

generator enclosure permanent interior form plate; steam generator supports; structural steel

framing (including embedded steel); sump screens (coarse) and associated framing; sump

screens (fine); threaded fasteners (CRDM support structure); threaded fasteners (ice basket);

and threaded fasteners (RCS component support (reactor vessel, steam generators, RCPs,

pressurizer)).

Those made of concrete include the containment base slab foundation, containment dome,

containment operating deck, containment wall, crane wall (upper) and ice condenser end walls,

exhaust dome and exhaust duct, fuel transfer canal walls and floodup overflow structure, ice

condenser support slab, ice condenser wear slab, lower containment concrete walls and floor

slabs, pressurizer enclosure, reactor cavity missile blocks, regenerative heat exchanger room

wall, and steam generator enclosures.

Those made of rubber include air lock seals, reactor pit membrane waterproofing, and

removable gate (bulkhead) seals.

Finally, those made of other materials include the ice condenser intermediate and upper deck

curtains.

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2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 and CNP UFSAR Chapter 5 to determine whether the

applicant identified the containment components within the scope of license renewal and

subject to AMR. The staff conducted its review in accordance with the guidance described in

Section 2.4 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 verify 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 within the scope of license renewal to verify 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's review of LRA Section 2.4.1 identified several areas in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results.

Therefore, the staff issued RAls 2.4-2 and 2.4-5 to the applicant concerning these specific

issues to determine whether it properly applied the scoping criteria of 10 CFR 54.4(a) and the

screening criteria of 10 CFR 54.21 (a)(1). By letter dated May 7, 2004, the applicant responded

to these two RAls.

The following summarizes the staff's concerns, the applicant's responses, and the staff's

evaluation of these two RAls.

RAI 2.4-2

Based on its review of LRA Sections 2.1, 2.2, 2.3, 2.4, and 2.5, the staff issued RAI 2.4-2, as

follows, which identified the following issues related to scoping and screening:

a. It is not clear to the staff if the applicant has addressed thermal insulation

on piping and structures in its scoping and screening evaluation.

b. LRA Section 2.4.1 (Page 2.4-2) states that: "Seals are provided on the

boundary of the lower and upper compartments and on the hatches in the

operating deck to limit steam bypassing the ice condenser." However,

LRA Table 2.4-1 does not appear to include these seals.

c. LRA Section 2.4.1 identifies the equipment hatch as part of the

containment structure evaluation boundary. However, LRA Table 2.4-1

does not appear to include the equipment hatch. . ~:

For each issue above, the applicant is requested to (1 ) identify if it is within the

scope of license renewal; (2) if not within the scope of license renewal, provide

the technical basis for that determination; (3) if within the scope of license

renewal, identify the specific table and row in LRA Section 2.3 or 2.4 that

includes the item; and (4) if within'the scope of license renewal, identify the

location in LRA Section 3 that addresses the AMR for the item.:

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The applicant responded to RAI 2.4-2 as follows:

a. For information related to thermal insulation on piping, refer to the RAI

2.1-5 response.

Structural thermal insulation is addressed in the scoping and screening

evaluation as follows:

(1) The thermal barriers for the ice condenser, wall duct panels,

intermediate and upper deck curtains, and concrete walls are

within the scope of license renewal.

(2) Not applicable-within the scope of license renewal.

(3) The thermal barriers for the ice condenser, wall duct panels,

intermediate and upper deck curtains, and concrete walls are

included in the 'Ice condenser intermediate and upper deck

curtains" entry in LRA Table 2.4-1 on page 2.4-16.

(4) The "Ice condenser intermediate and upper deck curtains" entry in

LRA Table 3.5.2-1 on page 3.5-40 addresses the aging

management review for these items.

b. Seals that provide a boundary between the lower and upper

compartments are of three types.

(1) Divider barrier seals between the bottom of the ice condenser

compartment slab and the containment wall and up the sides of

the ice condenser end walls.

(2) Divider barrier hatch seals provided on the hatches in the

operating deck.

(3) Divider barrier penetration seals installed around penetrations and

openings through the divider barrier.

For these seals,

(1) All three types of seals described above are within the scope of

license renewal. The seals are sub-components within the

containment structure and are not explicitly called out.

LRA Table 2.2-3 lists the containment as a structure within scope.

(2) Not applicable-within the scope of license renewal.

(3) The first two types of seals, divider barrier seals and the divider

barrier hatch seals, are not listed in LRA Table 2.4-1 as subject to

aging management review since they are considered short-lived.

The determination that the divider barrier seals and the divider

barrier hatch seals are short-lived is based on guidance in the

SOC and in NUREG-1800.

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Statements of Consideration (SOC) on "Long-Lived"- SRP Section 2.1.3.2.2:

"It is important to note, however, that the Commission has

decided not to generically exclude passive structures and

components that are replaced based on performance or condition

from an [AMR] ...such generic exclusion is not

appropriate....However, the Commission does not intend to

preclude a license renewal applicant from providing site-specific

justification in a license renewal application that a replacement

program on the basis of performance or condition for a passive

structure or component provides reasonable assurance that the

intended function of the passive structure or component will be

maintained in the period of extended operation."

Specific Staff Guidance on "Consumables" SRP Table 2.1-3-

"...The consumables in category (c) are short-lived and

periodically replaced, and can be excluded from an AMR on that

basis. Likewise, the consumables that fall within category (d) are

typically replaced based on performance or condition monitoring

that identifies whether these components are at the end of their

qualified lives and may be excluded, on a plant-specific basis,

from AMR under 10 CFR 54.21(a)(1)(ii)."

The divider barrier seals are inspected and replaced based on

their condition in accordance with CNP Technical Specification

Surveillance Requirement 4.6.5.9. The divider barrier hatch seals

are visually inspected before final closure each outage and

replaced as needed and are inspected every ten years per CNP

Technical Specification Surveillance Requirement 4.6.5.5.2.

Therefore, these seals are short-lived and not subject to aging

management review. The divider barrier penetration seals are

listed in the "Divider barrier penetration seals" entry in

LRA Table 2.4-5 on page 2.4-22.

(4) The "Divider barrier penetration seals" entry in LRA Table 3.5.2-5

on page 3.5-66 addresses the aging management review for

divider barrier penetration seals.

c. The equipment hatch is grouped with the personnel airlocks in the

component type 'Air lock doors." The equipment hatch is located near

the top of the fuel transfer canal. One personnel access opening is

located within the equipment hatch; The other is located at the

instrument room, El. 612'. The component type "Air lock doors"

corresponds to items 3.5.1-4 and 3.5.1-5 "Personnel airlock and

equipment hatch" in LRA Table 3.5-1 on page 3.5-17.

(1) The equipment hatch is within the scope of license renewal and is

subject to aging management review.

(2) Not applicable-within the scope of license renewal.

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(3) The equipment hatch is included in component type "Air lock

doors" entry in LRA Table 2.4-1 on page 2.4-14.

(4) The "Air lock doors" entry in LRA Table 3.5.2-1 on page 3.5-27

addresses the aging management review for the equipment

hatch.

The following summarizes the staff's evaluation of the applicant's response.

Part (a)

In its response to part (a) of the RAI, the applicant referred to its response to RAI 2.1-5 for

information related to thermal insulation on piping. In its response to RAI 2.1-5, the applicant

stated the following:

Insulation that functions only to maintain the environment (temperature) during

normal operation does NOT perform an intended function as described in

10 CFR 54.4. An example of such insulation is that which is installed on hot

piping in containment. Degradation of this insulation could result in local

concrete temperature exceeding the temperature assumed for the environment

in the aging management review. However, maintaining the environment

assumed for the aging management review is not an intended function, as

described in 10 CFR 54.4.

This quote from the RAI 2.1-5 response presents a good case for including the thermal

insulation within the scope of license renewal in accordance with 10 CFR 54.4(2).

In its response to RAI 2.1-5, the applicant erroneously paraphrased and interpreted the Generic

Aging Lessons Learned (GALL) Report and SRP-LR recommendations for aging management

of concrete exposed to elevated temperature, indicating that the Structures Monitoring Program

is sufficient to manage such aging. This is not the case for the hot containment penetrations,

which are the most susceptible locations for this type of degradation (see GALL Report,

Chapter II Al, Item A1.1-h (page 11 Al -8), and SRP-LR Section 3.5.3.2.1.3 (page 3.5-7) for

containment; see GALL Report Chapter III Al, Item A1.1-j (page III A1-9), and SRP-LR Section

3.5.3.2.2.1 (page 3.5-8) for Class I structures).

In its response to RAI 2.1-5, the applicant closed with an argument that there are no AERMs for

insulation in an indoor environment and quoted from the staff SER for the Calvert Cliffs license

renewal (NUREG-1705) to support its argument.

If the applicant does not credit thermal insulation to maintain the temperature of concrete below

degradation threshold levels and concludes that the concrete may be subject to long-term

overheating if the insulation degrades, then the applicant must provide a plant-specific AMP to

detect any change in concrete material properties resulting from long-term exposure to elevated

temperatures. The staff concluded during the development of the GALL Report that visual

examination is not sufficient to detect change in material properties of concrete resulting from

long-term exposure to elevated temperatures.

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Part (b)

In its response to part (b) of the RAI, the applicant identified three types of divider barrier seals:

(1) divider barrier seals between the bottom of the ice condenser compartment slab and the

containment wall and up the sides of the ice condenser walls

(2) divider barrier hatch seals provided on the hatches in the operating deck

(3) divider barrier penetration seals installed around penetrations and openings through the

divider barrier

The applicant stated that all three types of seals are within the scope of license renewal. The

staff finds this acceptable. However, the applicant indicated that only the divider barrier

penetration seals are subject to an AMR, because it considers the first two types of seals to be

short-lived. The applicant stated that this determination "is based on guidance in theStatements of Consideration and in NUREG-1800" and selectively quotes from SRP Section

2.1.3.2.2 (Statements of Consideration on long-lived") and SRP Table 2.1-3 (guidance on

consumables") to support its determination.

Based on review of the complete text of these SRP sections, the applicant's interpretation of the

Statements of Consideration is questionable, and the applicant erroneously quoted from the

discussion of category (c) and (d) consumables, while seals are category (a) consumables.

The applicant stated the following:

The divider barrier seals are inspected and replaced based on their condition in

accordance with CNP Technical Specification Surveillance Requirement 4.6.5.9.

The divider barrier hatch seals are visually inspected before final closure each

outage and replaced as needed and are inspected every ten years per CNP

Technical Specification Surveillance Requirement 4.6.5.5.2.- Therefore, these

seals are short-lived and not subject to aging management.

The 10 CFR 54.21 (a)(1 )(ii) criterion for inclusion within the scope of license renewal is SCs

"that are not subject to replacement based on a qualified life or specified time period." The two

types of seals in question are inspected and replaced based on their condition, 'which is exactly

what aging management for license' renewal is intended to accomplish. It would be more

appropriate for the applicant to credit the current inspection activities and technical specification

requirements as the license renewal AMP for these seals than to claim that they are the basis

for exclusion from the scope of license renewal.

Part (c)

The applicant's response to part (c) of the RAI is acceptable because it clarifies that the

equipment hatch is included in the license renewal scope. - - -

The staff did not consider the applicant's responses to RAI 2.4-2 parts (a) and (b) to be

acceptable, because they do not provide sound technical bases for the applicant's conclusions.

In telephone conference calls with the applicant held on May 17, 2004, May 21,-2004. and

November 10, 2004, the staff described its concerns about parts (a) and (b) of the response,

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and requested that the applicant submit additional information to address the concerns. The

applicant submitted the following supplemental responses to RAI 2.4-2 parts (a) and (b), by

letter dated November 18, 2004:

Supplementary Response to RAI 2.4-2 part (a):

[Note: The applicant has addressed this issue in a supplementary response to

RAI 2.1-5 on the same subject]

The NRC Staff requested l&M to clarify whether piping thermal insulation serves

an intended function in accordance with 10 CFR 54.4, and to provide the basis

for the determination as to whether this piping thermal insulation requires aging

management. In an RAI response dated August 11, 2004, ...I&M stated that

piping insulation is not in scope and not subject to aging management review,

except in certain specific applications where the insulation is required to maintain

post-accident temperature in areas housing safety-related equipment. The NRC

Staff has indicated a need for additional information regarding the review of

piping thermal information. Based on a conference call with the NRC Staff on

November 10, 2004, 1&M understands that the specific information required

pertains to the review of the piping thermal insulation at containment

penetrations.

Thermal insulation on hot piping at containment penetrations does not meet the

scoping criteria of 10 CFR 54.4. 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 NRC 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 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). Therefore, thermal

insulation on hot piping at containment penetrations does not meet the scoping

criteria of 10 CFR 54.4. This is consistent with the previously approved staff

position documented in NUREG-1766, Safety Evaluation Report Related to the

License Renewal of North Anna Nuclear Station, Units 1 and 2, and Surry

Nuclear Power Station, Units 1 and 2.

Notwithstanding the above, l&M agrees to include the insulation on hot

containment piping penetrations in the scope of license renewal. The intended

function that was applied to the insulation is to prevent excessive heat

transmission to the containment concrete surrounding the piping penetrations.

The insulation is encapsulated with stainless steel jacketing in the annulus

between the penetration piping and the penetration sleeve. There are no

applicable aging effects for insulation in the indoor air environment. A review of

CNP operating experience for the past five years verified that the plant has not

experienced aging-related degradation of piping insulation in dry indoor

environments. Therefore, based upon the material, environment, and operating

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experience, the insulation is not expected to degrade, and an AMP is not

required.

The staff finds the applicant's supplementary response to RAI 2.4-2 part (a) acceptable

because the applicant has included the insulation on hot containment piping penetrations in the

scope of license renewal.

Supplementary Response to RAI 2.4-2 part (b):

In RAI responses dated May 7, 2004, and August 11, 2004,...1&M stated that the

divider barrier seals and divider barrier hatch seals are short-lived and not

subject to aging management review because they are periodically inspected in

accordance with Technical Specifications 4.6.5.9 and 4.6.5.5.2, respectively.

I&M's position was based on NRC statements regarding NUREG-1800, Section

2.1.3.2.2, "Long-Lived," in the Statements of Consideration for the Final License

Renewal Rule. Upon further consideration, I&M has determined that it would be

more appropriate to credit inspection activities that implement plant Technical

Specification requirements as the license renewal AMP for the divider barrier

seals and divider barrier hatch and personnel access seals than to credit the

Technical Specification requirements as the basis for exclusion from aging

management review.

To implement this change, the Updated Final Safety Analysis Report (UFSAR)

supplement for the Structures Monitoring - Divider Barrier Seal Inspection

Program provided in LRA Sections A.2.1.37 and the affected program element

descriptions from LRA Section B.1.34 are modified as provided below. New text

is italicized, as follows:

A.2.1.37 Structures Monitoring - Divider Barrier Seal Inspection Program

The Divider Barrier Seal Inspection Program detects cracking and

change in material properties of the elastomeric divider barrier seals,

divider barrier hatch and personnel access door seals, and pressure

seals for penetrations and openings through the containment divider

barrier. The program detects aging effects through analysis of main

dividerbarrierseal test coupons and visual examination of the three

types of seals between the upper and lower containment -

compartments.

B.1.34 Structures Monitoring - Divider Barrier Seal Inspection Program

Program Description

The Divider Barrier Seal Inspection Program is an existing plant-specific

program. There is no comparable NUREG-1 801 program.

The divider barrier in each containment is the physical boundary that separates

upper containment from lower containment. Several containment internal

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structures constitute the divider barrier. Elastomeric seals are provided for the

divider barrier that separates the upper and lower containment compartments;

and for the personnel access doors, equipment hatches, and penetrations and

openings through the divider barrier where it is necessary to limit potential ice

condenser bypass leakage subsequent to a postulated pipe rupture or loss of

coolant accident. Cracking and change in material properties are aging effects

requiring management for the pressure seals.

Aging Management Program Elements

Scope The scope of this program is the elastomeric containment divider barrier

seals; and elastomeric hatch seals, personnel access door seals, and pressure

seals around penetrations and openings through the divider barrier.

Parameters Monitored or Inspected Parameters monitored by this program are

cracking and change in material properties of elastomeric pressure seals.

Detection of Aging Effects This program detects cracking and change in

material properties prior to loss of the pressure seals' intended functions.

In accordance with plant Technical Specifications, (1) the physical properties of

the main divider barrier seals are periodically verified through analysis of seal

test coupons, and (2) visual inspections of the divider barrier seals and hatch

and personnel access door seals are performed to identify apparent deterioration

of the seal material. The seals around penetrations and openings (including the

bulkhead gate) are visually inspected to ensure the absence of apparent

deterioration (cracks or defects). The frequency of the penetration and openings

seals inspection is at least once every 10 years.

Monitoring and Trending This program monitors aging effects through analysis

of main divider barrier seal test coupons and visual examination of the other

seals. The Corrective Action Program provides reasonable assurance that

trends entailing repeat failures to meet acceptance criteria will be identified and

addressed with appropriate corrective actions.

Acceptance Criteria The acceptance criteria for the divider barrier seal test

coupons is provided in plant Technical Specifications. The acceptance criteria

for visual seal inspections are that seals must be free of unacceptable

deterioration (excessive cracks or defects) and unacceptable misalignment.

Corrective Actions Discrepancies noted during the inspection are documented in

the Corrective Action Program in accordance with the implementing procedure.

Specific corrective actions will be implemented in accordance with the CNP

Corrective Action Program. Required actions for failure to meet the Technical

Specification surveillance requirements applicable to the main divider barrier

seals and divider barrier hatch and personnel access door seals are provided in

the plant Technical Specifications.

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-

In addition, in LRA Tables 2.4-1, on Page 2.4-16 and 3.5.2-1, on Page 3.5-40,.

the Component entry "Removable gate (bulkhead) seals" is modified to read as

follows:

* Main divider barrier seals

* Divider barrier hatch seals

* Personnel access door seals

* Removable gate (bulkhead) seals

The staff finds the applicant's supplementary response to RAI 2.4-2 part (b) acceptable

because the divider barrier seals and divider barrier hatch seals are now treated as passive,

long-lived components that are subject to an AMR, and the applicant has committed to manage

aging of these components under CNP AMP B.1.34, "Structures Monitoring-Divider Barrier

Seal Inspection Program."- ...

Therefore, RAI 2.4-2 is considered resolved from the scoping and screening perspective.

However, the staff additionally needed to evaluate and accept the applicant's AMR results for

thermal insulation. The evaluation was provided in the supplemental response to RAI 2.1-5 (see

Section 2.1.3.1.4 for staff evaluation of the supplemental response to RAI 2.1-5).

RAI2.4-5

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 staff requested that the applicant clarify whether the cable feed-through

assembly is within the scope of license renewal. If it is within scope, The staff requested that

the applicant 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 the cable

feed through assembly is not within the scope of license renewal, the applicant was asked to

provide the justification for its exclusion.

The applicant submitted the following response to RAI 2.4-5, by letter dated May 7, 2004:

LRA Table 2.1.1 identifies electrical portions of electrical and instrumentation and

control penetration assemblies (i.e., electrical penetration assembly cables and

connections) as a commodity group that serves an intended function. The cable

feed-through assemblies are part of these electrical penetrations, and are

therefore in scope for license renewal.

As described in LRA Section 2.1.2.3.3, all electrical penetration assemblies

(including the cable feed-through assemblies) are included in the EQ Program.

Under the EQ Program, cable feed-through 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.

In addition to replacing these components based on a qualified life, the EQ

Program also incorporated pressure testing of the cable feed-through

assemblies in the qualification of the electrical containment penetrations.

Furthermore, while not subject to aging management review, electrical

2-155 -
I

penetrations are tested in accordance with the requirements of

10 CFR 50 Appendix J. Steel elements of the penetrations were included in the

containment aging management review as "Containment penetrations

(mechanical and electrical)," listed in LRA Tables 2.4-1 and 3.5.2-1, on pages

2.4-14 and 3.5-28 through 3.5-29.

The staff's evaluation of the applicant's response is described below:

The containment pressure boundary function of the cable feed-through assembly needs to be

evaluated as part of the containment structure scope. Appendix J local leak rate testing should

be credited (along with any other program the applicant wishes to credit) to manage aging of

the cable feed-through assembly for its containment pressure boundary function. The

applicant's initial response to RAI 2.4-5 was not acceptable because the applicant did not credit

Appendix J local leak rate testing as an AMP for the containment pressure boundary function.

In telephone conference calls with the applicant held on May 17, 2004, May 21, 2004, and

November 10, 2004, the staff described its concerns about the response, and requested that

the applicant submit additional information to address these concerns. The applicant submitted

the following supplemental response to RAI 2.4-5, by letter dated November 18, 2004:

In response to an NRC staff request pertaining to activities credited to ensure the

cable feed-through assemblies will perform their pressure-retaining function

throughout the period of extended operation, l&M provided, in a letter dated

August 11, 2004, ...a discussion that credited the electrical penetration pressure

testing that was performed to satisfy the 10 CFR 50.49 environmental

qualification (EQ) requirements and 10 CFR 50 Appendix J containment leakage

rate testing. Subsequently, the NRC staff requested that l&M specifically credit

10 CFR 50 Appendix J, Type B testing (or any other AMP) for license renewal, to

ensure the pressure boundary integrity of cable feed-through assemblies. The

NRC staff further requested that l&M identify the AMP that it is crediting for

license renewal.

Pressure testing during environmental qualification of the electrical containment

penetrations provides assurance that the pressure boundary integrity of cable

feed-through assemblies will be maintained during the period of extended

operation. In addition, the Containment Leakage Rate Testing Program, as

described in LRA Section B.1.8, is credited with managing the effects of aging on

containment electrical penetrations throughout the period of extended operation

by providing assurance that leakage through these penetrations does not exceed

allowable values. Local leakage rate testing (defined as "Type B testing in

10 CFR 50 Appendix J), performed under the Containment Leakage Rate

Testing Program, provides ongoing confirmation of the integrity of resilient seals

around the perimeter of the cable feed-through assemblies. Integrated leakage

rate testing (defined as "Type A testing" in 10 CFR 50 Appendix J), performed

under the Containment Leakage Rate Testing Program, provides additional

confirmation of pressure boundary integrity of the feed-through assemblies.

The staff finds the applicant's supplemental response to be acceptable because the applicant

credited 10 CFR Part 50 Appendix J, Type A and Type B testing for license renewal, to ensure

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the pressure boundary integrity of cable feed-through assemblies. Therefore, the staff's

concern described in RAI 2.4-5 is resolved.

2.4.1.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the Containment. Therefore,

the staff concludes that the applicant has adequately identified the SCs that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately

identified the Containment SCs subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.2 Auxiliary Building

2.4.2.1 Summary of Technical Information in the Application

In Section 2.4.2 of the LRA, the applicant identified the SCs of the auxiliary building that are

subject to an AMR for license renewal. The auxiliary building supports and protects plant

equipment, including much of the nuclear steam supply system and other auxiliary systems

necessary for the safe operation of CNP, Units 1 and 2. The two CNP units share the auxiliary

building, which houses common areas, as well as sections dedicated to each unit. The auxiliary

building encloses the fuel storage areas, diesel generator rooms,'switchgear rooms,-control

facilities, and other equipment. The auxiliary building is primarily a T-shaped structure located

between the Unit 1 and 2 containment buildings. The auxiliary building also includes the

C-shaped structures that border each of the containment buildings and enclose the electrical

tunnels and main steamlines. The building is principally a reinforced concrete structure:

consisting mainly of exterior and interior walls, flat roofs, floor slabs, 'and a flat foundation mat.

The building is classified as a safety related, seismic Class I structure.' -

The safety intended functions of the auxiliary building are to support and protect safety related

plant equipment. The auxiliary building provides physical support for itself, ESF, and other

systems and equipment located within the structure. 'The exterior walls and roofs of the

auxiliary building protect against tomado-generated or turbine-generated missiles and provide

protection against the weather for systems and equipment within the structure. The auxiliary

building includes the SFP and liner, which maintain a sufficient water inventory to provide

shielding and cooling for the fuel. -

The auxiliary building also supports and protects safe-shutdown equipment related to'Appendix

R to 10 CFR Part 50 and equipment used to cope with an SBO. The auxiliary building includes

nonsafety related commodity groups that must maintain mechanical and structural integrity so

that nearby safety related equipment is not adversely affected.

Therefore, the auxiliary building 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 2.4-2 of the LRA, the applicant identified steel auxiliary building component types that

are within the scope of license renewal and subject to an AMR, including block wall grating and

framing, cranes and rails and supports, elevator support steel, EDG air intake missile shield

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framing, EDG air intake missile shield grating, louver framing (EDG and switchgear), missile

shield, new fuel storage racks, spent fuel pit steel (including swing gate, attachments, liner, and

fuel racks), and superstructure framing,

The applicant also identified concrete components, including the electrical tunnel, elevator

masonry block, exterior walls, floor slabs, fuel transfer canal, foundation, interior walls, internal

flood curbs, main steamline enclosure, masonry block, roof, spent fuel pit walls and slab, and

sump.

2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2 and CNP UFSAR Section 2.9 to determine whether the

applicant identified the auxiliary building components within the scope of license renewal and

subject to an AMR. The staff conducted its review in accordance with the guidance described

in Section 2.4 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 verify 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 within the scope of license renewal to verify 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 auxiliary building that meet the

scoping requirements of 10 CFR 54.4 within the scope of license renewal and identified them

as such in LRA Section 2.4.2. Table 2.4-2 of the LRA includes the specific component types

that are subject to an AMR in accordance with 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1).

2.4.2.3 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 SCs of the auxiliary building. Therefore, the

staff concludes that the applicant has adequately identified the SCs that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the auxiliary building SCs that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.4.3 Turbine Building and Screenhouse

2.4.3.1 Summary of Technical Information in the Application

In Section 2.4.3 of the LRA, the applicant identified the SCs of the turbine building and

screenhouse that are subject to an AMR for license renewal. CNP Units 1 and 2 share the

turbine building and screenhouse, which house several common areas (such as the makeup

plant), as well as sections dedicated to each unit. The turbine building and screenhouse protect

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plant equipment, including the MT, generator, and auxiliary equipment in the turbine building

and the CW pumps and ESW pumps in the screenhouse.

The turbine building is a three-tiered structure that adjoins the auxiliary building.- It includes the

turbine room, the heater bay areas, and the service bay areas. The turbine building and:

screenhouse share a masonry wall and a seismic Class I foundation. The AFW and ESW.:

pumps and their associated piping systems are housed within protective seismic Class I -

structures supported by the foundation.

The screenhouse is a concrete structure located adjacent to Lake Michigan. Below the

superstructure of the building are the pump bays and piers, which guide traveling screens that

collect debris and fish. Below the grade on the north and south sides of the screenhouse are

discharge tunnels that connect the condensers and discharge piping. Two discharge pipes run

out into Lake Michigan. Between the screenhouse and the shore, there is a 20-foot-wide - ---

concrete roadway. Below this roadway are the screenhouse forebay and its connection to the

de-icing tunnels and intake pipes. The three intake-pipes connect the intake cribs, located

underwater, to the forebay.

The turbine building is principally reinforced concrete at and below the grade of elevation,

consisting mainly of exterior and interior walls, floor slabs, turbine and generator pedestals, and

a flat, seismic Class I foundation mat. Above the grade, the turbine building is essentially a

steel superstructure covered by aluminum siding.

Within the screenhouse, concrete barriers protect the ESW pumps against turbine missiles and

from fires or other accidents in the adjacent ESW pump compartments. In addition, the ESW

pump compartments are designed to withstand tornado-velocity wind effects and tornado-borne

missiles. Flood protection to Elevation 595' is provided for safety related components. The

ESW pump motors are above Elevation 595' and are therefore adequately protected from the

maximum flood condition anticipated from a seiche or surge phenomenon.

The intended functions of the turbine building and screenhouse are to-support and protect

safety related plant equipment. The turbine building and screenhouse provide physical support

for themselves and other systems and equipment located within the structures. The walls and

roofs of the .turbine building and screenhouse protect against tornado-generated or turbinegenerated missiles and provide weather protection to the systems and equipment within the

structure. The turbine building and screenhouse include nonsafety related commodity groups

that must maintain mechanical and structural integrity so that nearby safety related equipment

is not adversely affected. The turbine building and screenhouse also support and protect

Appendix R to 10 CFR Part 50 safe-shutdown equipment and equipment used to cope with an

SBO.

Therefore, the turbine building and screenhouse are 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 2.4-3 of the LRA, the applicant identified the steel turbine building and screenhouse

component types that are within the scope of license renewal and subject to an AMR, including

the AFW pump room doors 226, 227, 228, 229; intake corrugated piping; intake crib framing

and plate; miscellaneous steel (catwalks, handrails, ladders, platforms, stairs,-and associated

-supports) in the ESW and AFW pump rooms; miscellaneous steel (ladders and associated

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supports) in the forebay; screenhouse forebay bar grille and base; sheet piling; and

superstructure framing.

The applicant also identified concrete component types, including 12-inch-thick concrete wall;

essential motor control center room walls; ESW pump room; AFW pump room (walls, floor, and

ceiling); de-icing tunnels; discharge tunnels and bays; foundation mat (turbine building and

screenhouse); intake cribs (surrounding sacked concrete); masonry block (4-hour rated);

screenhouse below grade walls, beams, and slabs; screenhouse exterior abovegrade walls;

and superstructure steel column concrete encasing.

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 and CNP UFSAR Section 2.9 to determine whether the

applicant identified the turbine building and screenhouse components within the scope of

license renewal and subject to AMR. The staff conducted its review in accordance with the

guidance described in Section 2.4 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 verify 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 within the scope of license renewal to verify 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).

RAI 2.4-3

The staff's review of the LRA Section 2.4.3 identified one area in which it needed additional

information to complete its evaluation of the applicant's scoping and screening results and

determine whether the applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the

screening criteria of 10 CFR 54.21(a)(1). The staff requested the following additional

information related to the scoping and screening of water-control structures in RAI 2.4-3:

The staff has reviewed the following information submitted by the applicant, in

order to identify all of the structures and components that are essential to ensure

access to the ultimate heat sink (Lake Michigan), for safe shutdown following a

design basis event:

* LRA Section 2.3.3.2 (Essential Service Water);

* LRA Section 2.3.3.11 (Screen Wash System);

* LRA Section 2.4.3 (Turbine Building and Screenhouse);

* UFSAR Section 9.8.3 (Service Water Systems);

* UFSAR Section 10.6 (Circulating Water System);

* UFSAR Figure 1.3-1 (Plot Plan);

* UFSAR Figure 10.6-1 (Circulating Water System)

As a result of this review, additional information are needed before the staff can

reach a conclusion that all essential elements have been included in the LR

scope and have been subject to aging management review.

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LRA Section 2.4.3, under "Evaluation Boundaries", lists the structural elements

that are evaluated for the turbine building and screenhouse. The following

elements in the list appear to directly relate to the availability of cooling water for

safe shutdown:

* Screenhouse superstructure, which houses the ESW and CW (circulating

water) pumps, As well as the traveling screens, stop logs, and bar grills

* Structural components and commodities from, and including, the intake cribs

up to but not including the CW pump intake piping

! -, .- .- ;,

* Structural components and commodities from, and including, the intake cribs

up to but not including the ESW pump intake piping - - -

* Structural components and commodities from, and including, the discharge

tunnels up to, and including, the discharge jets

* Structural components and commodities that support CW pumps and intake

piping

* Structural components and commodities that support ESW pumps and intake

piping

* Structural components and commodities associated with the following: Intake

cribs; Discharge piping; Forebay; Traveling screens; Trash baskets; Trash

collection; Sluice gates; De-icing tunnels; Discharge tunnels; Screenhouse;

Piping supports, pump supports, baseplates, and anchors contained within

the screenhouse.

However, many of the elements listed above are not specifically identified in

LRA Table 2.4-3, 'Turbine Building And Screenhouse Components Subject to

Aging Management Review", and only two (2) items in the table specify an

intended function USCW" (provide source of cooling water for plant shutdown).

These are intake corrugated steel piping and intake crib steel framing and plate.

LRA Table 2.4-5, "Structural Commodities Components Subject to Aging

Management Review", does not list any components specifically related to the

availability of cooling water for safe shutdown. --

Therefore, the applicant is requested to:

(a) List all structures and components depicted in UFSAR Figure 10.6-1

(Circulating Water.System), and any additional structures and components,

that are essential to ensure the availability of cooling water for safe

shutdown, up to (but not including) the ESW pumps; -

(b) Correlate the list developed in response to (a) above with the structures and

components identified in LRA Section 2.4.3 "Evaluation Boundaries";

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(c) For each listed structure and component, identify the applicable line item in

LRA Table 2.4-3 or LRA Table 2.4-5;

(d) If it is not included in either of these tables, identify where it is addressed in

the LRA; and

(e) Identify the applicable AMR reference for each structure and component.

The applicant submitted the following response to RAI 2.4-3, by letter dated May 7, 2004:

The structures and components that are essential to ensure availability of cooling

water for safe shutdown and perform an intended function per 10 CFR 54.4(a)

are the de-icing tunnels, discharge tunnels, forebay, intake cribs, intake pipe, screenhouse, and traveling screens. These structures and components are

depicted in UFSAR Figure 10.6-1 "Circulating Water System." The structures

and components that are not essential to ensure availability of cooling water for

safe shutdown include the sluice gates, roller gates, stop log guides, and the

discharge elbows.

Correlation of evaluation boundaries in LRA Section 2.4.3 to line items in

LRA Table 2.4-3, and to structures and/or components/commodities (i.e., aging management review references) in LRA Table 3.5.2-3 is provided in the table

below. All structures and components related to cooling water availability are

correlated to line items in the referenced LRA Tables.

Item Evaluation Boundaries Line Item in LRA

Tables 2.4-3 and 3.5.2-3

De-icing tunnels

Discharge tunnels

Structural components and

commodities that support ESW and

CW pumps and intake piping and

those associated with the de-icing

tunnels

Structural components and

commodities from, and including, the

discharge tunnels up to, and

including, the discharge jets and

those associated with the discharge

tunnels

De-icing tunnels

Discharge tunnels and bays

Forebay Screenhouse superstructure which

houses the ESW and CW pumps, as

well as the traveling screens, stop

logs, and bar grilles and those

associated with the forebay

Screenhouse forebay bar

grille and base

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Item Evaluation Boundaries Line Item in LRA

Tables 2.4-3 and 3.5.2-3

Intake crib

Intake crib

Intake pipe

Screenhouse

Screenhouse

Screenhouse

Screenhouse

Screenhouse

Traveling scree

Structural components and'

commodities that support ESW and

CW pumps and intake piping and

those associated with the intake cribs

Structural components and

commodities from, and including, the

intake cribs up to but not including the

ESW and CW pump intake piping and

those associated with the intake cribs

Structural components and

commodities that support ESW and

CW pumps and intake piping

Screenhouse superstructure which

houses the ESW and CW pumps, as

well as the traveling screens, stop

logs, and bar grilles

Interior and exterior masonry,

including concrete walls and slabs,

concrete block walls, concrete pads,

and embedded equipment supports

Interior and exterior masonry,

including concrete walls and slabs,

concrete block walls, concrete pads,

and embedded equipment supports

Interior and exterior masonry,

including concrete walls and slabs,

concrete block walls, concrete pads,

and embedded equipment supports

Screenhouse superstructure which

houses the ESW and CW pumps, as

well as the traveling screens, stop

logs, and bar grilles

!ns Structural components and -

commodities from, and including, the

intake cribs up to but not including the

-CW pump intake piping and those

associated with the traveling screens

I ntake crib framing and plate

Intake cribs (surrounding

sacked concrete)

Intake corrugated piping

Superstructure framing

Screenhouse below grade

walls, beams, and slabs

Screenhouse exterior above

grade walls

Table 2.4-3-Foundation mat

(turbine building and

screenhouse)

' Table 3.5.2-5- Foundation

mat (screenhouse) '

Superstructure steel column

concrete encasing

Not applicable.' The screens

move in order to perform

their function. Since these

components are active, they

are not subject to aging

management review.

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The following provides the staff's evaluation of the applicant's response:

UFSAR Section 10.6.2 states: "However in the unlikely event of complete loss of flow

to the screen house through the intake pipes adequate flow for essential service water

requirements can be provided from the discharge pipes. This is accomplished by

opening motor operated sluice gates separating the discharge pipes from the screen

house forebay." UFSAR Section 9.8.3.2 also states: 'It is inconceivable that damage

from barge or ship accidents or even natural phenomena could totally isolate these

three pipes; however, motor operated sluice gates which normally separate the

discharge from the intake can be opened providing another access to the lake."

UFSAR Section 10.6.2 also states: "De-icing capability to the intake cribs is provided by

shutting off flow in the middle intake pipe to the screen house, by closing its motor

operated sluice gate and sending a portion of 'warm' discharge water from either the

Unit 1 or Unit 2 discharge tunnel back through the middle pipe to the lake."

In light of the above information from the UFSAR, the sluice gates, roller gates,

discharge piping, and discharge elbows appear to be essential to ensure availability of

cooling water for safe shutdown. The response to RAI 2.4-3 specifically states that the

sluice gates, roller gates, and discharge elbows are not essential. The applicant needs

to explain why the sluice gates, roller gates, and discharge elbows are not essential.

Discharge piping is not discussed in the RAI response. The applicant needs to address

the discharge piping, including the technical basis for determining whether it is or is not

essential to ensure availability of cooling water for safe shutdown.

2. The response to RAI 2.4-3 indicates that the traveling screens perform an intended

function per 10 CFR 54.4(a). However, for the item "Traveling Screens" in the table, the

response states 'The screens move in order to perform their function. Since these

components are active, they are not subject to aging management review." Are the

structural components of the traveling screens subject to periodic inspection for

degradation? If so, under what current program? If not, how is performance of

intended function ensured?

3. The response to RAI 2.4-3 does not address the trash baskets and trash collection. The

applicant needs to address these items, including the technical basis for determining

whether they are or are not essential to ensure availability of cooling water for safe

shutdown.

4. The response to RAI 2.4-3 does not clearly address the "discharge jets". The applicant

needs to describe the physical location and function of the discharge jets, and

specifically indicate whether they are essential to ensure availability of cooling water for

safe shutdown, and perform an intended function per 10 CFR 54.4(a).

In telephone conference calls with the applicant held on May 17, 2004 and May 21, 2004, the

staff described its concerns about the response and requested that the applicant submit

additional information to address the SE concerns. The applicant submitted the following

supplemental response to RAI 2.4-3, by letter dated August 11, 2004:

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The applicant's original response to RAI 2.4-3, provided in the May 7, 2004 RAI

response letter, identified the structures and components depicted in UFSAR

Figure 10.6-1 (Circulating Water System) that are and are not essential to

ensure availability of cooling water for safe shutdown. This supplemental

response provides clarification to the original RAI 2.4-3 response by revising and

expanding the first paragraph of the original RAI 2.4-3 response to provide the

basis for determining the structures and components essential for the flowpath

relied u'pon for safe shutdown. Additionally, the original RAI 2.4-3 response

provided a'table to correlate the items listed in LRA Section 2.4.3, Evaluation

Boundaries, to line items in LRA Tables 2.4-3 and 3.5.2-3. This supplemental

response clarifies the correlation for the traveling screen structural supports,

which were not specifically addressed in the table in the original RAI response.

The flow path relied on for safe shutdown to ensure the availability of cooling

water to the ESW pumps is through the intake pipes to the forebay and

screenhouse and then to the ESW pump. ;The structures and components that

are essential for this flow path are the forebay, intake cribs, intake pipes,

screenhouse, and traveling screens. The de-icing tunnel and the discharge

tunnels are not part of the required flow path but are considered subject to aging

management review because they are structurally integral to the screenhouse

foundation. These structures and components are depicted in UFSAR Figure

10.6-1. The structures and components that are not essential to ensure

availability of cooling water for safe shutdown include the sluice gates, roller

gates, stop log guides, discharge elbows, and discharge corrugated piping

terminating at'the discharge elbows.

The discharge elbows and the discharge corrugated piping terminating at the

discharge elbows shown on UFSAR Figure 10.6-1 are not relied on to ensure the

availability of cooling water to the ESW pumps. Sluice gates and roller gates

can be aligned to supply water to the ESW. pumps from the lake through the

discharge piping; however, as discussed in UFSAR Section 9.8.3.2, damage

from barge or ship accidents or even natural phenomena that could totally isolate

these three pipes is not credible. As the maximum demand foi the ESW system

is a small fraction (approximately one percent) of the total circulating water

system demand during normal operation, and the intake pipes would not be.

totally isolated by a postulated accident or natural phenomenon, the alternative

intake flowpath through the discharge piping using the roller gates and sluice

gates is not required to ensure the availability of water to the ESW pumps.

The sluice gates and roller gates also provide de-icing capability to the intake

cribs. De-icing is accomplished by closing the motor-operated sluice gate to

shut off flow to the screenhouse from the middle intake pipe and sending a

portion of "warm" discharge water from either the' Unit 1 or Unit 2 discharge

tunnel back through'(via.the de-icing tunnel) the middle pipe to the lake. The

heated water will recirculate to the other two'intake pipes thus keeping the

intakes free of ice. De-icing supports normal plant operation and is not credited

for emergency operation since warm circulating water flow would not be available

with a loss of offsite power. 'Therefore, sluice gates and roller-gates do not.

perform a license renewal intended function.

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The stop log guides are not safety related and do not perform a license renewal

intended function. The purpose of the stop log guides is to hold temporary stop logs in place to allow inspections or maintenance.

As provided in the original RAI 2.4-3 response, the entry in LRA Section 2.4.3, Evaluation Boundaries, applicable to the traveling screens is, "Structural*

components and commodities from, and including, the intake cribs up to but not

including the CW pump intake piping and those associated with the traveling screens." The original response correctly noted that the screens are active

components and are not subject to aging management review. This

supplemental response clarifies that the structural supports for the screens are

part of the screenhouse structure, which is in scope for license renewal and

subject to aging management review.

The staff's evaluation of the supplemental response concluded that the applicant still did not

adequately address the trash baskets, trash collection, and the 'discharge jets." In addition, in

the supplemental response that addresses de-icing, the applicant stated the following:

De-icing supports normal plant operation and is not credited for emergency operation since warm circulating water flow would not be available with a loss of

offsite power. Therefore, sluice gates and roller gates do not perform a license

renewal intended function.

The staff was not clear which components are relied on during emergency operation to ensure

an adequate supply of cooling water for safe shutdown.

In a telephone conference call with the applicant held on November 10, 2004, the staff

described its concerns about the supplemental response, and requested that the applicant submit additional information to address the concerns. The applicant submitted the following supplemental response to RAI 2.4-3, by letter dated November 18, 2004:

In letters dated May 7, 2004, and August 11, 2004, ...I&M provided responses to

RAI 2.4-3, regarding the structures and components that are essential to ensure

the availability of cooling water for safe shutdown and perform an intended

function per 10 CFR 54.4(a). Subsequently, the NRC Staff requested the

following information:

* Determine whether the trash baskets and associated trash collection

equipment are essential to ensure availability of cooling water for safe

shutdown [RAI 2.4-3, Part (3)].

* Describe the physical location and function of the discharge jets and

specifically indicate whether they are essential to ensure availability of

cooling water for safe shutdown and perform an intended function per 10 CFR 54.4(a) [RAI 2.4-3, Part (4)).

* Identify the components that are relied on for de-icing to ensure an adequate supply of cooling water for safe shutdown, and verify that all of these

components are included in the license renewal scope.

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Part (3) of the response to RAI 2.4-3 did not address the trash baskets and

associated trash collection equipment used for trash collection. Trash collection

equipment is used to collect the trash that is removed from the traveling screens

by the screen wash system and direct it to the trash baskets. After being filled,

the baskets are used to transport the trash for disposal. The trash baskets and

associated trash collection equipment are not-in the flow path for water entering

the screen house and providing suction to the essential service water (ESW)

system. Failure of the trash baskets and associated trash collection equipment

would not impact the ability to provide water to the ESW system. Therefore, they

do not meet the scoping criteria of 10 CFR 54.4.

Part (4) of the response to RAI 2.4-3 did not clearly address the "discharge jets."

The discharge jets are at the end of the discharge piping in the lake and act as a

diffuser to direct flow away from the intake pipes and distribute the water so as to

minimize the environmental effects of the warm water. The discharge jets are

located downstream of the discharge corrugated piping and the discharge

elbows shown on UFSAR Figure 10.6-1. As discussed in l&M's supplemental

response to RAI 2.4-3, included in the August 11, 2004, letter, ...the discharge

piping and discharge elbows are not relied upon to ensure the availability of

cooling water to-the ESW pumps. Therefore, the discharge piping, elbows, and

jets do not meet the 10 CFR 54.4 scoping criteria.

The operation of sluice gates and roller gates is needed to establish the flow

path for de-icing. De-icing is not credited for emergency operation. Icing is a

concern only for the higher flow rates associated with power operation. The

concern during power operation is flow restriction caused by ice fouling the

traveling screens. The flow restriction can result in the circulating water system''

being unable to provide the flow necessary to support power operation. During

emergency operation, required flow is a small fraction (approximately one

percent) of total circulating water capacity. At the significantly lower flow rate

required for emergency operation, ice fouling of the traveling screens will not

prevent the required flow from reaching the suction of the ESW system pumps.

During emergency operation, de-icing is not required to assure the availability'of

'-the cooling water supply to the ESW system.' The mechanical components

credited to-ensure an adequate supply of cooling water for safe shutdown'during

cold weather operation are the ESW pumps, intake piping,' strainers, and valves.'

The staff finds that the applicant's initial and supplemental responses to RAI 2.4-3 provide an

acceptable technical basis to define'the water:control SCs that are essential to achieve safe'

shutdown. In addition, the applicant included these SCs in the license renewal scope.

Therefore, the staff's concerns described in RAI 2.4-3 are resolved.

2.4.3.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the turbine building and

screenhouse.- Therefore, the staff concludes that the applicant adequately identified the SCs

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

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applicant adequately identified the turbine building and screenhouse SCs that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.4.4 Yard Structures

2.4.4.1 Summary of Technical Information in the Application

In Section 2.4.4 of the LRA, the applicant identified the SCs of the yard structures that are

subject to an AMR for license renewal. Yard structures are structures at CNP not contained

within major buildings, such as the screenhouse, turbine building, auxiliary building, and

containment buildings. The yard structures within the scope of license renewal include the

following:

* fire protection pump house

* flood protection earth (under roadway)

* gas bottle storage tank rack and foundation

* roadway

* security diesel generator room

* switchyard control house

* tank area pipe tunnel (condensate storage, refueling water storage, and emergency

diesel generator piping tunnel)

* tank foundations

- condensate storage tank

- fire protection water storage tank

- primary water storage tank

- refueling water storage tank

* towers

- Unit 1 power delivery to switchyard tower

- Unit 2 power delivery to switchyard tower

* transformer pedestals

* trench from switchyard to startup transformers (duct bank)

Yard structures do not have a specific structural function; rather, they generally support other

plant system functions (i.e., FP, containment spray, CCW, and ESW). The yard structures

have no unique supports. Section 2.4.5 of the LRA addresses supports with the bulk

commodities. Table 2.2-4 of the LRA provides a list of structures not within the scope of license

renewal.

In Table 2.4.4-1 of the LRA, the applicant listed the scoping criteria from 10 CFR 54.4 met by

each yard structure.

In Table 2.4-4 of the LRA, the applicant identified the steel yard structures component types

that are within the scope of license renewal and subject to an AMR, including the FP pump

house superstructure, gas bottle storage tank rack, and Tower - Unit 2 power delivery to the

switchyard.

The applicant also listed the concrete component types, including FP pump house walls, FP

pump house foundation, gas bottle storage tank foundation, roadway, security diesel generator

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room, switchyard control house, tank area pipe tunnel, tank foundations (refueling water

storage), tank foundations (condensate storage), tank foundations (FP water storage), tank

foundations (primary water storage), tower (Unit 1 power delivery to switchyard), transformer

pedestals (startup), and trench from switchyard to startup transformers (duct bank).

Finally, the applicant listed the earth component types, including the roadway (shoreline).

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4 to determine whether the applicant identified the yard

structures within the scope of license renewal and subject to AMR. The applicant stated that

the CNP UFSAR does not contain structural details of these structures. The staff conducted its

review in accordance with the guidance described in Section 2.4 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA to verify

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 within the scope of license renewal to verify 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 yard structures that meet the

scoping requirements of 10 CFR 54.4 within the scope of license renewal and identified them

as such in LRA Section 2.4.4. Table 2.4-4 of the LRA includes the specific component types

that are subject to an AMR in accordance with 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1).

2.4.4.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, and

licensing basis information, the staff did not identify any omissions or discrepancies in the

applicant's scoping and screening results for the SCs of the yard structures. 'Therefore, the

staff concludes that the applicant adequately identified the SCs that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and components that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

2.4.5 Structural Commodities

2.4.5.1 Summary of Technical Information in the Application

In Section 2.4.5 of the LRA, the applicant identified the SCs of the structural commodities that

are subject to an AMR for license renewal. 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 that are common to CNP in-scope systems and structures (i.e.,

anchors, embedments, equipment supports, instrument panels, racks, cable trays, and

conduits) are evaluated as bulk commodities.'

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In Table 2.4-5 of the LRA, the applicant identified the steel structural commodities component

types that are within the scope of license renewal and subject to an AMR, including baseplates;

baseplates embedded unistrut; battery racks; blowout panels; cable tray and conduit supports;

cable trays and conduits; component supports; cranes, rails, and girders; doors and framing

(nonfire-rated); electrical instrument panels and enclosures; fire damper framing (in-wall); fire

doors; HVAC duct supports; instrument line supports; instrument racks and frames;

miscellaneous embedments; pipe sleeves (mechanical and electrical, not penetrating the

containment liner plate); piping supports; roof flashing; stairs, ladders, platforms, and grating

(supports); and tube tracks.

The applicant also identified steel (threaded fasteners) component types, including anchor

bolts, equipment hatch and personnel access openings threaded fasteners, other threaded

fasteners, other threaded fasteners (SFP stainless steel fasteners), and reactor cavity missile

block tie-downs.

Concrete component types include cable trays and conduits, flood curbs, hatches, fireproofing,

support pedestals, and trenches (pipe and cable).

Elastomer component types include building pressure boundary sealant, cable trays and

conduits, divider barrier penetration seals, fire barrier seals, floor plugs, joint elastomer at

seismic gaps, penetration seals, roof elastomer, and water stops.

Nonelastomer component types include fire barriers (cable trays).

Finally, other component types include roofing above battery rooms.

2.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5 to determine whether the applicant identified the

structural commodities within the scope of license renewal and subject to AMR. The applicant

stated that the UFSAR does not contain details of the aging effects or aging management of

these commodities. The staff conducted its review in accordance with the guidance described

in Section 2.4 of the SRP-LR.

In conducting its review, the staff evaluated the system functions described in the LRA to verify

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 within the scope of license renewal to verify that it

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).

With one possible exception, the staff found that the applicant included the structural

commodities that meet the scoping requirements of 10 CFR 54.4 within the scope of license

renewal and identified them as such in LRA Section 2.4.5. Table 2.4-5 of the LRA includes the

specific component types that are subject to an AMR in accordance with 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1). The exception is thermal insulation that may serve an intended function to

limit the temperature of containment concrete to 65 OC (150 0F) general and 93 0C (2000F) local

during normal operation. The staff requested additional information on this subject as part of

RAI 2.4-2. Section 2.4.1.2 of this SER documents the resolution.

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2.4.5.3 Conclusion

During its review of the information provided in the LRA, license renewal drawings, licensing

basis information, and RAI responses, the staff did not identify any omissions or discrepancies

in the applicant's scoping and screening results for the SCs of the structural commodities.

Therefore, the staff concludes that the applicant has adequately identified the SCs that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1). -

2.5 Scoping and Screening Results-Electrical and Instrumentation and Controls

Systems

This section addresses the scoping and screening results for electrical and l&C systems at

CNP, Units 1 and 2, for license renewal. Pursuant to 10 CFR 54.21 (a)(1), an applicant must

identify and list SCs subject to an AMR, including passive, long-lived SCs that are within the

scope of license renewal. To verify that the applicant has properly implemented its

methodology, the staff focuses its review on the implementation results. This 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 does not identify an omission, the staff has the basis to find that there

is reasonable assurance that the applicant identified the electrical system components that are

subject to an AMR.

2.5.0 Staff Evaluation Methodology

The staff performed its evaluation of the information provided in the LRA in the same manner

for all electrical and l&C systems. The review sought to determine whether the applicant

identified the SSCs for a specific electrical or l&C system 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 verify that all

long-lived, passive components are subject to an AMR in accordance with 10 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 are not identified 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 licensing basis documents to determine whether-the LRA

specifies all intended functions delineated under 10 CFR 54.4(a). If the staff identified'

omissions, it 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 whether such

functions are performed with moving parts or a change in configuration or properties, or - -

whether they are subject to replacement based on a qualified life-or specified time period, as'

described in 10 CFR 54.21 (a)(1). For those that 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 10 CFR 54.21 (a)(1). If the staff identified discrepancies, it requested additional information

to resolve them.

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2.5.1 Summary of Technical Information in the Application

The applicant developed a listing of electrical and l&C component commodity groups for

systems and structures within the scope of license renewal, as well as active/passive

determinations, following the guidance of Appendix B to NEI 95-10. The applicant did not

identify any commodity groups beyond those listed in Appendix B to NEI 95-10.

The applicant reviewed these electrical and l&C component commodity groups (determined to

be passive) to identify those that are not subject to replacement based on a limited qualified life

or specified time period.

Based on its review, the applicant determined that the following electrical and l&C component

commodity groups are subject to an AMR:

* electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

* electrical cables used in instrumentation required by the technical specifications for

high-voltage, low-current circuits not subject to 10 CFR 50.49 EQ requirements

* inaccessible medium-voltage (4.16 kV to 34.5 kV) cables (i.e., installed in conduit or

direct buried) 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 for SBO connections

* high-voltage insulators

All other electrical and l&C component commodity groups are not subject to an AMR because

they are (1) active, (2) subject to replacement based on a qualified life or specified time period

(long-lived screening), or (3) do not perform any intended functions (scoping).

2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.5 to determine whether there is reasonable assurance that

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 10 CFR 54.4 and

10 CFR 54.21 (a)(1).

In performing the review, the staff selected system functions described in the UFSAR that are

set forth in 10 CFR 54.4 to verify that components having intended functions were not omitted

from the scope of 10 CFR Part 54. The staff also reviewed drawings and focused on

components that the applicant did not identify as subject to an AMR to determine whether it

omitted any components.

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RAI 2.5-3

In a letter dated May 6, 2004, the staff requested clarification on the numbering of the table on

page 2.1-17 of the LRA. The paragraph leading to Table 2.1.1 on page 2.1-17 of the LRA

refers to Table 2.1-1, which does not exist in the LRA. In response to the staff RAI 2.5-3, by

letter dated June 8, 2004, the applicant clarified that, consistent with the labeling convention for

other LRA Section 2 tables, the table labeled 2.1.1 on LRA pages 10 and 2.1-17 should have

been labeled Table 2.1-1. This editorial explanation is acceptable to the staff. Therefore, the

staff's concern described in RAI 2.5-3 is resolved.

RAI 2.5-4

The staff also requested, in RAI 2.5-4, clarification on the statement in LRA Section 2.1.2.3.3

that all electrical penetration assemblies are included in the Environmental Qualification

Program and are not subject to AMR. The applicant responded that all of the electrical

penetrations, including the penetration assemblies, are safety related and are included in its

Environmental Qualification Program, described in LRA Section B.2.1. The staff finds this

confirmation acceptable. Therefore, the staff's concern described in RAI 2.5-4 is resolved.

RAI 2.5-5

In RAI 2.5-5, the staff requested additional information on how the applicant will treat nonsafety

related cables (not within the scope of license renewal) that share conduits or raceways with inscope cables included in the AMR. The applicant confirmed that all non-EQ insulated cables

installed in structures within the scope of license renewal are included in the scope of license

renewal regardless of safety classification. The applicant quoted from LRA Section 2.1.1,

which states, "A bounding scoping approach was used for electrical equipment and systems.

Electrical and l&C systems as well as Electrical and l&C components in mechanical systems

were within the scope of license renewal." The applicant further quoted the following from LRA

Section 2.5:

The basic philosophy for Electrical and l&C component integrated plant

assessment (IPA) was that all components were included in the review.

Including components beyond those actually required is referred to as an

"encompassing" or a "bounding" review. This method eliminates the need for

unique identification of each component and its specific location. This method

also assured components were not inadvertently excluded from an AMR.

The applicant stated that the commodity group "electrical cables and connections not subject to

10 CFR 50.49 EQ requirements" contains nonsafety related and safety related cables; no

cables were eliminated from this commodity type based on intended function. The applicant

concluded that, as a part of the bounding approach, it will treat all of these non-EQ insulated

cables equally for the license renewal AMR. Based on these confirmations, the staff concludes

that the AMR program will include all nonsafety related cables that share conduits or raceways

with in-scope cables included in the AMR. Therefore, the staff's concern described in RAI 2.5-5

is resolved.

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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 components that are subject to

an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1).

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3. AGING MANAGEMENT REVIEW RESULTS

This section of the safety evaluation report (SER) contains the Nuclear Regulatory Commission

(NRC) staff's evaluation of the applicant's aging management programs (AMPs) and aging

management reviews (AMRs). In Appendix B to the license renewal application (LRA), the

applicant described the 46 AMPs that it relies on to manage or monitor the aging of long-lived,

passive structures and components (SCs). In Section 3 of the LRA, the applicant provided the

results of the AMRs for those SCs that it identified in Section 2 of the LRA as within the scope

of license renewal and subject to an AMR.

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

In preparing its LRA, Indiana Michigan Power Company (I&M or the applicant) credited

NUREG-1 801, "Generic Aging Lessons Learned (GALL) Report," issued July 2001. The GALL

Report contains the staff's generic evaluation of the existing plant programs and documents the

technical basis for determining existing programs that are adequate without modification and.

existing programs that 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 SCs for license renewal without

change. The GALL Report also contains recommendations on specific areas for which existing

programs should be augmented for license renewal' An applicant may reference the GALL

Report in its LRA to demonstrate that the programs at its facility correspond to those reviewed

and approved in the report.

The GALL Report provides the staff with a summary of NRC-approved AMPs to manage or

monitor the aging of 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 also serves as a reference for applicants and staff

reviewers to quickly identify those AMPs and activities that the staff has determined will

adequately manage or monitor aging during the period of extended operation.

The GALL Report identifies (1) structures, systems, and components (SSCs), (2)SC materials,

(3) the environmen ts 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 demonstration project to exercise the GALL process and

to determine the format and content of a safety evaluation (SE) based on this process. The

results of the demonstration project confirm that the GALL process will improve the efficiency

and effectiveness of the LRA review while maintaining the staff's focus on public health and

safety. The staff prepared NUREG-.1800, "Standard Review Plan for the Review of License

Renewal Applications," (SRP-LR) issued April 2001, based on both the GALL Report model and

lessons learned from the demonstration project.

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I

For its review of the LRA for the Donald C. Cook Nuclear Plant (CNP), Units 1 and 2, the staff

performed audits and reviews during the weeks of December 15, 2003; March 1, 2004; and

April 12, 2004, to verify that AMPs and AMR results that the applicant claimed are consistent

with the GALL Report are indeed consistent. The staff conducted a public exit meeting on April

15, 2004.

The document titled, "Audit and Review Report for Plant Aging Management Reviews - Donald

C. Cook Nuclear Plant, Units 1 and 2," dated September 22, 2004, hereafter referred to as the

audit and review report, documents the results and findings of this effort.

3.0.1 Format of the Licence Renewal Application

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 following two

types of tables present the AMR results information in Section 3 of the LRA:

(1) In Table 1, numbered as Table 3.x.1, "3" indicates the LRA section number, "x" indicates

the subsection number from the GALL Report, and "1" indicates that this is the first table

type in Section 3 of the LRA.

(2) In Table 2, numbered as Table 3.x.2-y, "3" indicates the LRA section number, ux"

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 CNP LRA is essentially the same. In revising

the format for the CNP LRA, the applicant intended 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 Overview of Table 1

Table 3.x.1 (Table 1) provides a summary comparison aligning the facility with the

corresponding tables in the GALL Report, Volume 1. The table is essentially the same as

Tables 1 through 6 provided in the GALL Report, Volume 1, except that an "Item Number"

column replaces the "Type" column and a "Discussion" column replaces the "Item Number in

GALL" column. The "Item Number" column provides the reviewer with a means to

cross-reference from Table 2 to Table 1. The applicant used the "Discussion" column to

provide clarifying/amplifying information. This column might contain the following types of

information:

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* further evaluation recommended-information or reference to where that information is

located

* the name of a plant-specific program

* 'exceptions to the GALL Report assumptions

* a discussion of how the line is consistent with the corresponding line item in the GALL

Report when that may not be intuitively obvious

* - a discussion of how the item is different than the corresponding line item in the GALL

Report (i.e., when there is exception taken to an AMP that is listed in the GALL Report)

The format of Table 1 allows the staff to align a specific Table 1 row with the corresponding

GALL Report, Volume 1, table row so that consistency can be checked easily.

3.0.1.2 Overview of Table 2

Table 2 provides the detailed results of the AMRs for those components identified in LRA

Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the components or

systems within a system grouping (ie., reactor coolant systems (RCSs), engineered safety

features (ESFs), auxiliary systems). For example, the ESFs group contains tables specific to

the containment spray system, containment isolation system, and emergency core cooling

system (ECCS). Table 2 consists of the following nine columns:

(1) The first column, "Component Type," identifies the component types from Section 2 of

the LRA that are subject to an AMR and lists them in alphabetical'order.

(2) The second column, "Intended Function," contains the license renewal intended

functions (including abbreviations where applicable) for the listed component types. The

LRA Section 2 intended functions table contains definitions and abbreviations of

intended functions.

(3). The third column, "Material," lists the particular materials of construction for the

component type.

(4) The fourth column, "Environment," lists the internal and external service environments to

which the component types are exposed. The LRA Section 3 internal service

environments and external service environments tables provide a list of these

environments.

(5) The fifth column lists aging effects requiring management (AERMs). As part of the AMR

process, the applicant determined any AERMs for each material and environment

combination .

(6) The sixth column, "Aging Management Programs," lists the AMPs the applicant used to

manage the identified aging effects.

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(7) The seventh column, "GALL Volume 2 Item," lists the GALL Report item(s) that the

applicant identified in its LRA as similar to the AMR results. The applicant compared

each combination of component type, material, environment, AERM, and AMP in Table

2 of the SER to the items in the GALL Report. If there is 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 correspond to items in the GALL Report tables.

(8) The eighth column, 'Table 1 Item," *lists the corresponding summary item number from

Table 1. If the applicant identified AMR results in Table 2 that are consistent with the

GALL Report, then Table 2 lists the associated Table 3.x.1 line summary item number.

If there is no corresponding item in the GALL Report, then column eight is left blank.

This allows the information from the two tables to be correlated.

(9) The ninth column, "Notes," lists the corresponding notes that the applicant used to

identify the alignment of the information in Table 2 with the information in the GALL

Report. An NEI working group developed the notes identified by letters, which will be

used in future LRAs. Numbers identify plant-specific notes, which 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, AMPs, and information for which

further evaluation is recommended from the SRP-LR, no additional staff review of those

columns is required. The staff reviewed information provided by the applicant in the discussion

column or other sections of the LRA to determine whether the applicant's AMR results and

AMPs are 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:

(1) For items the applicant stated are consistent with the GALL Report, the staff conducted

an audit.

(2) For items the applicant stated are 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.

(3) For other items, the staff conducted a technical review.

3.0.2.1 Review of Aging Management Programs

For those AMPs for which the applicant claimed consistency with the GALL AMPs, the staff

conducted an audit to verify that the applicant's AMPs are, indeed, consistent with the AMPs in

the GALL Report. For each AMP that has one or more deviations, the staff evaluated each

deviation to determine (1) whether the deviation is acceptable and (2) whether the AMP, as

modified, will adequately manage the aging effect(s) for which it was credited.

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For AMPs that the GALL Report does not evaluate, the staff performed a full review to

determine the adequacy of the AMPs. The staff evaluated the AMPs against the following 10

program elements defined in Appendix A to the SRP-LR:

(1) The Scope of Program element should include the specific structures and components

subject to an AMR for license renewal.

(2) The Preventive Actions element should prevent or mitigate aging degradation.

(3) The Parameters Monitored or Inspected element should be linked to the degradation of

the particular structure and component intended functions(s).

(4) The Detection of Aging Effects element process should occur before there is a loss of

structure and 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) The Monitoring and Trending element should provide predictability of the extent of

degradation and timely corrective or mitigative actions.

(6) The Acceptance Criteria element, against which the need for corrective action will be

evaluated, should ensure that the structure and component intended function(s) are

maintained under all current licensing basis (CLB) design conditions during the period of

extended operation.

(7) The Corrective Actions element, including root cause determination and the prevention

*of recurrence, should be timely.

(8) The Confirmation Process element should ensure that preventive actions are adequate

and that appropriate corrective actions have been completed and are effective.

(9) The Administrative Controls element should provide a formal review and approval

-process.

(10) The Operating Experience element, including past corrective actions resulting in

program enhancements or additional programs, should provide objective evidence to,

support the conclusion that the program will adequately manage the effects of aging so

that the SC intended function(s) will be maintained during the period of extended

operation.

The staff reviewed the applicant's Corrective Action Program and documents its findings in

Section 3.0.3 of this SER. The staff's evaluation of the Corrective Action Program includes

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.

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The staff reviewed the information concerning the Operating Experience program element for

the AMPs that are consistent with GALL Report AMPs and documented its findings in its audit

and review report.

The staff reviewed the Updated Final Safety Analysis Report (UFSAR) Supplement for each

AMP to determine if it adequately described the program or activity, as required by Title 10,

Section 54.21 (d), of the Code of Federal Regulations (10 CFR 54.21 (d)).

3.0.2.2 Review of Aging Management Review Results

Table 2 of the LRA contains information concerning the alignment of the AMRs with the AMRs

identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the intended

function, material, environment, AERM, and AMP combination for a particular component type

within a system. The applicant identified the AMRs that correlate between a combination in

Table 2 and a combination in the GALL Report by a referenced item number in the "GALL

Volume 2 Item" column. The staff conducted an audit to verify the correlation. When this

column is blank, it indicates that the applicant could not locate an appropriate corresponding

combination in the GALL Report. The staff conducted a technical review of these combinations

that are not consistent with the GALL Report. The next column, 'Table 1 Item," provides a

reference number that indicates the corresponding row in Table 1.

3.0.2.3 NRC-Approved Precedents

To help facilitate the staff review of the LRA, an applicant may reference NRC-approved

precedents to demonstrate that its non-GALL programs correspond to programs that the staff

had approved for other plants during its review of previous LRAs. When an applicant elects to

provide precedent information, the staff determines whether the material presented in the

precedent applies to the applicant's facility, determines whether the plant program is bounded

by the conditions for which the NRC evaluated and approved the precedent, and verifies that

the plant program contains the program elements (or attributes) of the referenced precedent.

In general, if the staff determines that these conditions are satisfied, it will use the information in

the precedent to frame and focus its review of the applicant's program.

It is important to note that precedent information 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

precedent, in and of itself, is not a sufficient basis to accept the applicant's program. Rather,

the precedent facilitates the review of the substance of the matters described in the applicant's

program. As such, in its documentation of its reviews of programs that are based on

precedents, the precedent information is typically implicit in the evaluation rather than explicit.

If the staff determines that a precedent identified by the applicant does not apply to the

particular plant program for which it is credited, the staff reviews the program in accordance

with the SRP-LR, without consideration of the precedent information. The applicant chose to

provide precedent information to support its selection of certain CNP programs. Therefore,

some of the staff reviews documented in this SER incorporate precedent information in the

manner described above.

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3.0.2.4 -UFSAR Supplement

Consistent with the SRP-LR for the AMRs and associated AMPs that it reviewed, the staff also

evaluated 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

fin performing its work, the staff relied heavily on the CNP LRA, the SRP-LR, and the GALL

Report. The staff also examined the applicant's precedent review documents and AMP basisdocuments (a catalog of the documentation used by the'applicant to develop or justify its AMPs)

and other applicant documents, including selected implementing procedures, to verify that the

applicant's activities and programs will adequately manage the effects of aging on SCs.

The staff's audit and review report documents any discrepancies or issues discovered during

the audit and review that required a formal response on the docket. If the staff did not docket

or resolve an issue before issuing this report, it prepared a request for additional information

(RAI) describing the issue and the information needed to resolve the issue. This SER

describes the outcome of any such RAls. Attachment 3 to the staff's audit and review report

lists the RAls associated with this effort.

Attachment 4 to the staff's audit and review report provides a list of documents reviewed by the

staff. 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 to the

LRA. The table indicates the GALL Report program with which the applicant claimed its AMP is

consistent (if applicable) and the SSCs that credit the program for managing or monitoring

aging. The table also provides the section of the SER that documents the staff's evaluation of

the program.

Table 3.0.3-1 CNP's Aging Management Programs

CNP's AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) J- Comparison - AMP(s) -- - ---That Credit the AMP - SER Section

Existing AMPs

Bolting and Torquing Plant specific NA Reactor Vessel, Internals 3.0.3.3.2

Activities and Reactor Coolant System;

(B.1.2) Engineered Safety Features

: - - System; Auxiliary Systems; - ._

Steam and Power

Conversion Systems

Boral Surveillance Plant specific NA Auxiliary Systems 3.0.3.3.3

(B.1 .3)

3-7
CNP's AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) Comparison AMP(s) That Credit the AMP SER Section

Boric Acid Corrosion Consistent with XI.M10 Reactor Vessel, Internals 3.0.3.2.1

Prevention enhancements and Reactor Coolant System;

(B.1.4) Engineered Safety Features

System; Auxiliary Systems;

Structures and Component

Supports; Electrical and

Instrumentation arid Controls

Bottom-Mounted Plant specific NA Reactor Vessel, Internals 3.0.3.3.4

Instrumentation and Reactor Coolant System

Thimble Tube

Inspection

(B.1 .5)

Containment Consistent XI.S4 Engineered Safety Features 3.0.3.1

Leakage Rate System; Auxiliary Systems;

Testing Structures and Component

(B.1.8) Supports

Control Rod Drive Consistent with XI.M1 1 Reactor Vessel, Internals 3.0.3.2.3

Mechanism and exception and Reactor Coolant System

Other Vessel Head

Penetration

Inspection

(B.1 .9)

Diesel Fuel Consistent with XI.M30 Auxiliary Systems 3.0.3.2.4

Monitoring exceptions

(B.1.1 0)

Fire Protection Consistent with XI.M26 Auxiliary Systems; Structures 3.0.3.2.5

(B.1.11.1) exceptions and and Component Supports

enhancements

Fire Water System Consistent with XI.M27 Auxiliary Systems 3.0.3.2.6

(B.1.11.2) exceptions and

enhancements

Flow-Accelerated Consistent XI.M17 Reactor Vessel, Internals 3.0.3.1

Corrosion and Reactor Coolant System;

(B.1.12) Auxiliary Systems; Steam

and Power Conversion

Systems

3-8
CNP's AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) Comparison AMP(s) That Credit the AMP SER Section

Inservice Consistent XI.M1 Reactor Vessel, Internals 3.0.3.1

Inspection-ASME and Reactor Coolant System

Section Xi, Inservice

Inspection,

Subsection IWB,

IWC, IWD

(8.1.14)

Inservice Consistent with XI.S1 Structures and Component 3.0.3.2.7

Inspection-ASME exceptions Supports

Section Xi, Inservice

Inspection,

Subsection IWE

(B.1.1 5)

Inservice Consistent Xl.S3 Structures and Component 3.0.3.1

Inspection-ASME Supports

Section Xl, Inservice

Inspection,

Subsection IWF

(B. 1. 1 6)

Inservice Consistent with Xl.S2 Structures and Component 3.0.3.2.8

Inspection-ASME exceptions Supports

Section Xi, Inservice

Inspection,

Subsection IWL

(B.1.17)

Inservice Plant specific NA Engineered Safety Features 3.0.3.3.6

Inspection-ASME System

Section Xi,

Augmented

Inspections

(B.1.18)

Instrument Air Quality Plant specific NA Auxiliary Systems 3.0.3.3.7

(B.1.19) . .

Oil Analysis Plant specific NA Engineered Safety Features 3.0.3.3.8

(B.1.23) System; Auxiliary Systems;

Steam and Power . Conversion Systems

Pressurizer Plant specific NA Reactor Vessel, Internals 3.0.3.3.9

Examinations and Reactor Coolant System

(B.1.24) . .

3-9
CNP's AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) Comparison AMP(s) That Credit the AMP SER Section

Preventive Plant specific NA Engineered Safety Features 3.0.3.3.10

Maintenance System; Auxiliary Systems;

(B.1.25) Steam and Power

Conversion Systems

Reactor Vessel Consistent with XL.M31 Reactor Vessel, Internals 3.0.3.2.10

Integrity enhancements and Reactor Coolant System

(B.1.26)

Service Water Consistent with XL.M20 Engineered Safety Features 3.0.3.2.11

System Reliability exceptions and System; Auxiliary Systems

(B.1.29) enhancements

Steam Generator Consistent XI.M19 Reactor Vessel, Internals 3.0.3.1

Integrity Program and Reactor Coolant System

(B.1.31)

Structures Monitoring Consistent with XI.S6 Structures and Component 3.0.3.2.12

-Structures enhancements Supports

Monitoring

(B.1 .32)

Structures Monitoring Consistent with XI.M23 Structures and Component 3.0.3.2.13

-Crane Inspection exceptions and Supports

(B.1.33) - enhancements

Structures Monitoring Plant specific NA Structures and Component 3.0.3.3.11

-Divider Barrier Supports

Seal Inspection

(B.1 .34)

Structures Monitoring Plant specific NA Structures and Component 3.0.3.3.12

-ice Basket Supports

Inspection

(B.1 .35)

Structures Monitoring Consistent with XI.S5 Structures and Component 3.0.3.2.14

-Masonry Wall enhancement Supports

(B.1.36)

System Testing Plant specific NA Engineered Safety Features 3.0.3.3.13

(B.1.37) System; Auxiliary Systems;

Steam and Power

Conversion Systems;

Structures and Component Supports

3-10
CNP's AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) Comparison AMP(s) That Credit the AMP SER Section

System Walkdown Plant specific NA -Engineered Safety Features 3.0.3.3.14

(B.1.38) System; Auxiliary Systems;

Steam and Power

Conversion Systems

Water Chemistry Consistent with - Xl.M2 Reactor Vessel, Internals 3.0.3.2.15

Control-Primary and enhancements and Reactor Coolant System;

Secondary Water Engineered Safety Features

Chemistry Control System; Auxiliary Systems;

(B.1.40.1) Structures and Component

Supports

Water Chemistry Consistent with XI.M21 Reactor Vessel, Internals 3.0.3.2.16

Control-Closed exceptions : and Reactor Coolant System;

Cooling Water Engineered Safety Features

Chemistry Control System; Auxiliary Systems;

(B.1.40.2) Structures and Component

.___ _ _Supports_ 

Water Chemistry Plant specific NA Engineered Safety Features 3.0.3.3.16

Control-Auxiliary System; Auxiliary Systems;

Systems Water Steam and Power

Chemistry Control Conversion Systems

(B.1.40.3)

Environmental Consistent X.E1 3.0.3.1

Qualification of

Electric Component

(B.2.1) __

Fatigue Monitoring Consistent with X.M1 3.0.3.2.17

(B.2.2) exception and

enhancements

New AMPs -

Alloy 600 Aging Plant specific NA Reactor Vessel, Internals 3.0.3.3.1

Management (B.1.1) and Reactor Coolant System

Buried Piping Consistent with XI.M34 Auxiliary Systems 3.0.3.2.2

Inspection exception

(B.1.6)

Cast Austenitic Consistent XI.M12 Reactor Vessel, Internals 3.0.3.1

Stainless Steel . and Reactor Coolant System

Evaluation

(B.1.7)

Heat Exchanger Plant specific NA - Engineered Safety Features 3.0.3.3.5

Monitoring System; Auxiliary Systems;

(B.1.13) . Steam and Power

Conversion Systems

3-11
I

CNP's AMP GALL GALL LRA Systems or Structures Staffs

(LRA Section) Comparison AMP(s) That Credit the AMP SER Section

Non-EQ Inaccessible Consistent XL.E3 Electrical and 3.0.3.1

Medium-Voltage Instrumentation and Controls

Cable

(B.1.20)

Non-EQ Consistent with XI.E2 Electrical and 3.0.3.2.9

Instrumentation exception Instrumentation and Controls

Circuits Test Review

(B.1.21)

Non-EQ Insulated Consistent XI.E1 Electrical and 3.0.3.1

Cables and Instrumentation and Controls

Connections

(B. 1.22)

Reactor Vessel Consistent XI.M16 Reactor Vessel, Intemals 3.0.3.1

Internals Plates, and Reactor Coolant System

Forgings, Welds, and

Bolting

(B. 1.27)

Reactor Vessel Consistent XI.M13 Reactor Vessel, Intemals 3.0.3.1

Internals Cast and Reactor Coolant System

Austenitic Stainless

Steel Components

(B.1.28)

Small Bore Piping Consistent XI.M32 Reactor Vessel, Internals 3.0.3.1

(B.1.30) and Reactor Coolant System

Wall Thinning Plant specific NA Engineered Safety Features 3.0.3.3.15

Monitoring System; Steam and Power

(B.1.39) Conversion Systems

Water Chemistry Consistent XI.M32 Reactor Vessel, Intemals 3.0.3.3.17

Control-Chemistry and Reactor Coolant System;

One-Time Inspection Engineered Safety Features

(8.1.41) System; Auxiliary Systems;

Steam and Power

Conversion Systems;

Structures and Component

Supports

3.0.3.1 AMPs That Are Consistent with the GALL Report

In Appendix B to the LRA, the applicant indicated that the following AMPs are consistent with

the GALL Report:

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* Cast Austenitic Stainless'Steel Evaluation Program

* Containment Leakage Rate Testing Program

* Flow-Accelerated Corrosion Program

* Inservice Inspection-ASME Section Xl, Inservice Inspection, Subsection IWB, IWC,

IWD Program

* -Inservice Inspection-ASME Section Xl, Inservice Inspection, Subsection IWF Program

* -Non-EQ Inaccessible Medium-Voltage Cable Program

Non-EQ Insulated Cables and Connections Program

Reactor Vessel Internals Plates, Forgings, Welds, and Bolting Program

Reactor Vessel Internals Cast Austenitic Stainless Steel Components Program

* -Small Bore Piping Program

* Steam Generator Integrity Program

* Environmental Qualification of Electrical Components Program

During an audit, the staff confirmed the applicant's claim of consistency, with the exception of

the Flow-Accelerated Corrosion; Reactor Vessel Internals Plates Forgings, Welds, and Bolting;

and Steam Generator Integrity Programs. The staff's audit and review report documents the

audit findings and conclusions; this section discusses these three programs. The staff

determined that these AMPs are consistent with the AMPs described in the GALL Report,

including the associated Operating Experience attribute.

3.0.3.1.1 Flow-Accelerated Corrosion

In Section B.1.12 of Appendix B to the CNP LRA, the applicant states that CNP AMP B1.12,

"Flow-Accelerated Corrosion Program," is consistent with GALL AMP XI.M17. The applicant

did not identify any exceptions. -During the audits and inspections, the staff noted that the CNP

Flow-Accelerated Corrosion (FAC) Program is consistent withg the GALL AMP, with an

exception. The Monitoring and Trending element of GALL AMP XI.M17 requires that if

degradation is detected such that the wall thickness is less than the minimum predicted

thickness, additional examinations are performed in adjacent areas to bound the thinning.

However, the CNP FAC Program bases its sample expansion determination on a threshold

criteria rather than on predicted thickness. Sample size is increased when inspections detect,

significant FAC wear resulting in a wall thickness threshold of less .than or equal to 60 percent

of nominal wall thickness. This is an exception to the GALL Report. In RAI B.1.12-1, the staff

requested that CNP provide a description of the FAC Program, as modified by the exception,

and provide justification for the exception regarding the criteria for performing additional

examinations. This was identified by the staff as Open Item B.1.12-1.

By letter dated January 21, 2005, the CNP provided additional information in response to Open

Item B.1.12-1, taking the position that the AMP is consistent with the GALL Report, with an

exception..

In the FAC Program description in GALL Section XI.M17, the Monitoring and Trending section

states, in part, that, 'If degradation is detected such that the wall thickness is less than' the

minimum predicted thickness, additional examinations are performed in adjacent areas to

bound the thinning." CNP stated that literal implementation of this statement from the GALL

description is not practical in many cases. -If very little degradation is predicted, measured wall

thickness may be less than the predicted thickness even though the calculated life of the

affected component may exceed the operating life of the plant. In this case, sample expansion

3-13
would not be warranted. Therefore, the applicant took an exception to the Monitoring and

Trending attribute of GALL, Section XI.M17.

The staff noted that the CNP FAC Program is based on industry guidance in the Electric Power

Research Institute (EPRI) report NSAC-202L-R2, "Recommendations for an Effective FlowAccelerated Corrosion Program," dated April 1999, which recommends increasing the sample

size when inspections of the sample detect significant FAC wear. In the CNP FAC Program,

significant FAC wear is defined as FAC resulting in a wall thickness of less than or equal to 60

percent of nominal wall thickness. Sample expansion is typically required if any component is

determined to have a wall thickness of less than or equal to 60 percent of nominal wall

thickness (must be greater than the allowed minimum wall thickness). In addition, the staff

noted that CNP FAC procedures require that a sample expansion be performed when

inspection results indicate that a component has a remaining life less than one operating cycle

based on a trending of wall thickness measurements. This covers situations where the

minimum wall thickness required may be greater than 60 percent of nominal wall thickness.

The staff found this exception to the GALL Report for sample expansion to be acceptable

because literal implementation of the sample expansion criterion is not practical in all cases,

particularly when the predicted wall thickness change is small and the change is close to the

measurement capabilities. Additionally, the staff finds this exception acceptable since the

applicant trends expected wall thinning values and requires that the projected acceptable wall

thickness be above a threshold value that is above 60 percent nominal wall thickness and

above minimum wall thickness. On the basis of the supplemental information submitted by the

applicant, all issues related to Open Item B.1.12-1 are resolved.

3.0.3.1.2 Reactor Vessel Internals Plates, Forgings, Welds, and Bolting

Summary of Technical Information in the Application

The applicant's reactor vessel internals (RVI) program is discussed in LRA Section B.1.27,

"Reactor Vessel Internals Plates, Forgings, Welds, and Bolting." The applicant states that this

program is new and will be comparable with GALL AMP XI.M16, "PWR Vessel Internals," upon

implementation prior to the period of extended operation. This program will supplement the RVI

inspections required by ASME Section Xl, Subsection IWB. The applicant will participate in

industry activities concerning aging on pressurized-water reactor (PWR) RVI components.

Staff Evaluation

Based on the limited information provided in LRA Section B.1.27, the staff could not verify the

applicant's consistency with GALL for many of the 10 elements in GALL AMP XI.M1 6. The LRA

did not mention the identification of the most susceptible items, an Attribute 1 concern. Nor

does it provide the specific water chemistry guidelines used, an Attribute 2 concern. It did not

discuss whether the applicant will employ enhanced visual VT-1 examinations or ultrasonic

testing (UT) in inspections for certain selected components and locations, an Attribute 4

concern. As a result, the staff issued RAI B.1.27-1. In its letter dated August 19, 2004, the

applicant provided detailed information addressing all 10 elements in GALL AMP XI.M16, which

makes the following element-by-element evaluation possible.

3-14
Scope of Program. This AMP applies to the RVI stainless steel and nickel-based alloy

components, as listed in LRA Table 3.1.2-2, "Reactor Vessel Internals (Westinghouse)":

* core barrel (barrel, flange, outlet nozzle, and fasteners)

* core baffle and former plates

* core baffle and former bolts

* iower core plate and lower support columns

* diffuser plate

* lower support plate and lower core plate support column cap

* secondary core support assembly (energy absorbers)

* clevis insert block and fasteners

* thermal shield

* upper support plate core support structure

* in-core instrumentation support structure

RAI B1.27-2

The program is designed to manage crack initiation and growth due to stress-corrosion

cracking (SCC) or irradiation-assisted SCC (IASCC), loss of fracture.toughness due to neutron

irradiation embrittlement, and distortion (dimensional changes) due to void swelling of these

components. Since the applicant participates in the PWR Materials Reliability Project Issues

Group (MRP) program for investigating the impacts of aging on PWR RVI and the

Westinghouse Owners Group (WOG) program for baffle and former bolting, accomplishing

these AMP objectives depends on whether the MRP and WOG programs have similar

objectives to the applicant's program. In RAI B1.27-2, the staff requested information to

demonstrate that the MRP and WOG programs address all key issues of this AMP (i.e., crack

initiation and growth due to SCC or IASCC, loss of fracture toughness due to neutron irradiation

embrittlement, and distortion due to void swelling).

The applicant indicated in a letter dated August 19, 2004 that the information presented to the

staff by the MRP.Reactor Internals Issues Task Group (ITG) on October 23, 2003, includes a

summary of activities to address the specific aging effects and associated aging mechanisms

listed in RAI B.1.27-2 (i.e., SCC, IASCC, loss of fracture.toughness, and void swelling). -The

staff has verified this information and concluded that the MRP program on RVI covers the aging

effects managed by this AMP. In addition to the WOG program for-baffle/former bolting,-the

MRP program tasks also include IASCC and void swelling of baffle/former bolts. Hence, the -

first part of RAI B.1.27-2 is closed. However, the applicant did not revise its commitment letter

regarding this AMP to address the second part of RAI B.1.27-2, in which the staff requested

that the applicant commit to submitting the Reactor Vessel Internals Plates, Forgings, Welds,

and Bolting Program for the staff's review and approval three years prior to the period of

extended operation. The applicant made such a commitment in its letter dated October 18,

2004 to supplement its commitment letter; therefore, RAI B.1.27-2 is closed. -This is

Commitment #36, which supersedes Commitment #18, in Appendix A of this SER.

RAI B. 1.27-1

Preventive Actions. The applicant stated in the letter dated August 19, 2004 that the Reactor

Vessel Internals Plates, Forgings, Welds, and Bolting Program is a condition monitoring

program. However, the Primary and Secondary Water Chemistry Control Program, which will

3-15
be referred to hereafter as Water Chemistry Control Program, is an effective preventive

program to deter SCC and localized corrosion of the stainless steel and nickel-based alloy RVI

components. The Water Chemistry Control Program includes periodic monitoring and control

of contaminants in accordance with the guidelines in the EPRI document TR-1 05714, " PWR

Primary Water Chemistry Guidelines," issued January 1999. This attribute is consistent with

the GALL Report because it specifies TR-105714 under Preventive Actions as the guideline document for the Water Chemistry Program.

Parameters Monitored or Inspected. The applicant stated that this AMP monitors SCC, IASCC, and void swelling through inspections for the RVI components listed above. The monitoring of

distortion caused by void swelling is an enhancement because GALL AMP XI.M1 6 does not

mention it. The staff verified that the GALL Report discusses only SCC and IASCC and loss of

fracture toughness due to neutron irradiation embrittlement or void swelling; therefore, this

attribute is consistent with the GALL Report with an enhancement.

Detection of Aging Effects. The applicant stated that this AMP will use a visual inspection to

detect cracking caused by SCC and IASCC and a volumetric inspection of critical locations (to be determined by the on-going MRP program) to assess cracking for baffle bolts. GALL AMP

XI.M16 calls for the adoption of enhanced VT-1 inspection for non-bolted components to

achieve a 0.0005 inch resolution. The applicant made a final response to RAI B.1.27-1 in its

letter dated October 18, 2004:

The appropriate visual acuity requirements for augmented visual inspection of

components, other than baffle bolts, will be based in part on the critical crack

size analysis. It is anticipated that augmented visual inspection may require VT-1 or enhanced VT-1 (defined in NUREG-1 801, Section XI.M-19, as the ability to achieve a 0.0005-inch resolution). As discussed in LRA Section B.1.27, CNP

will adopt appropriate MRP recommendations in the Reactor Vessel Internals

Plates, Forgings, Welds, and Bolting Program....

Since the applicant will adopt appropriate MRP recommendations in the Reactor Vessel

Internals Plates, Forgings, Welds, and Bolting Program, including enhanced VT-1 to achieve a

0.0005-inch resolution should MRP recommend it, part of RAI B.1.27-1 is resolved.

In terms of the inspection for baffle bolts, the applicant indicated in its August 19, 2004

response to RAI B.1.27-1 that it will use volumetric inspection on critical locations of baffle bolts

to detect cracking. This is consistent with the current MRP program and consistent with the

GALL Report's call for "other demonstrated acceptable inspection methods to detect cracks

between the bolt head and the shank" for bolted components. GALL AMP XI.M1 6 Element 4, "Detection of Aging Effects," does not discuss void swelling. Therefore, monitoring void

swelling is an enhancement to this GALL attribute. The staff will review the management of

void swelling when the applicant submits its final RVI Program for NRC review and approval 3

years prior to the actual implementation of this program. The NRC has been in dialogue with

the MRP regarding the progress of the program on RVI. This attribute is consistent with the

GALL Report with an enhancement.

Monitoring and Trending. The GALL Report requires inspection schedules be in accordance

with ASME Code, Section Xl, Subsection IWB-2400, "Inspection Schedule," and reliable

examination methods be used for susceptible components or locations. The applicant's

3-16
response stated, "Unit 1 will be inspected in the fifth inspection interval while Unit 2 will be

inspected iri the sixth interval, pri6o to the last year of the first license renewal period." This

proposed augmented inspection schedule is not consistent with the GALL Report because

IWB-2400, which the GALL Report recommends for augmented inspections, requires RVI core

supp6rt structures to be inspected once during 'each 10-year interval. It is premature to

evaluate this exception to the GALL Report now, considering that the MRP program on RVI has

not yet established the appropriate inspection methods and frequency of inspection for approval

by the NRC. The staff will review this issue when the applicant submits its final RVI Program

for NRC review and approval. The MRP program also includes identification of reliable'

examination methods for susceptible components or locations. When the NRC reviews and

approves the final AMP before its implementation, this attribute will be consistent with the GALL

Report, consistent with the GALL Report with an enhancement, or consistent with the GALL

Report with an exception, depending on6 the final inspection plan approved by the NRC.

Acceptance Criteria. The applicant's response stated that for the plates, forgings, welds, and

bolting (excluding baffle bolts) that will be visually inspected, critical crack size will be

determined by analysis prior to inspection; for components susceptible to void swelling, the

acceptance criteria will be developed prior to the inspection; and for baffle bolts, since cracking

is unacceptable, the critical number of baffle bolts needed to be intact will be determined by

analysis. For this attribute, the GALL Report provides guidance for flaw evaluation only, which -

requires the use of the ASME Code, Section Xl flaw evaluation acceptance criteria in IWB-3400

and IWB-3500. Therefore, for critical flaw size determination, the NRC will use the acceptance

criteria of IWB-3400 and IWB-3500. For void swelling, the staff will review its acceptance

criteria when the applicant submits its'final RVI Program for NRC review and approval. For the

critical number of intact baffle bolts determination, the MRP program presented to the staff was

not detailed enough to include this analysis; however, the staff will review this analysis and its

acceptance criteria, plant-specific or MRP, when the applicant submits its final RVI Program for

NRC review and approval. The applicant added the following sentence to the UFSAR

Supplement to clarify its commitments regarding participation in the EPRI MRP program on

RVI, this is Commitment #19 in Appendix A of this'SER:

I&M will participate in industry-wide programs designed by the PWR Materials,

Reliability Project Reactor Internals Issues Task Group for investigating the

impacts of aging on PWR vessel internal components.

In the October 18, 2004 final response, the applicant also clarified that in terms of the

augmented inspections for RVI plates, forgings, welds, and bolting, other than baffle bolts,

inspection results will be compared with the' appropriate acceptance standards of IWB-3400

and IWB-3500. If the acceptahce standards of IWB-3400 and IWB-3500 are not applicable to

specific RVI components that require augmented inspection, the applicant will use alternate

acceptance standards suggested by the MRP. RAI B.1.27-1 is completely resolved. Hence,

this attribute is consistent with the GALL Report. When the NRC reviews and approves the

acceptance criteria for void swelling and the critical number of intact baffle bolts needed before

the implementation of this program, this attribute will be consistent with the GALL Report with

enhancements.

Operating Experience. The applicant stated in LRA Section B.1.27 that its Reactor Vessel

Internals Plates, Forgings, Welds, and Bolting Program is a new program without plant-specific

operating experience. As discussed in Information Notice (IN) 84-18, "Stress Corrosion

3-17
I

Cracking in Pressurized Water Reactor Systems," issued 1984, SCC may occur during refueling operation when there are unacceptable levels of contaminants in the boric acid

purchased and airborne contaminants over the SFP. GALL AMP XI.M16 mentions cracking in

stainless steel baffle former bolts in foreign and U.S. plants. The applicant has recognized this

and plans to resolve it through its participation in the MPR program on RVI. This attribute is

consistent with the GALL Report.

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report, or consistent with the GALL Report with enhancements. In

addition, the staff has reviewed the exceptions to the GALL Report 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 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).

Therefore, the staff concludes that actions have been identified and have been or will be taken

to manage the effects of aging during the period of extended operation on the functionality of

SCs subject to an AMR such that the activities authorized by a renewed license will continue to

be conducted in accordance with the CLB, as required by 10 CFR 54.29(a).

3.0.3.1.3 Steam Generator Integrity

Appendix B.1.31, "Steam Generator Integrity," of the LRA presents the applicant's steam

generator AMP. The applicant describes the program as an existing CNP program that is

based on the NEI 97-06 Steam Generator Program Guidelines, which provide for detecting degradation of tubing and secondary side internals. The applicant stated that the program uses

nondestructive examination (NDE) techniques to identify tubes that are defective and require removal or repair according to the Technical Specifications. The applicant also stated that the

program is consistent with that described in the GALL Report, Section XI.M19, Steam

Generator Tube Integrity.

The staff reviewed the program described in LRA Appendix B.1.31 to determine whether the

applicant has demonstrated that the program will adequately manage the applicable aging effects in the CNP steam generators during the period of extended operation as required by 10 CFR 54.21 (a)(3).

Summary of Technical Information in the Application

All of the steam generators at CNP have tubes made from thermally treated Alloy 690, which is

considered a corrosion-resistant material for this application. According to Appendix B.1.31, the

steam generators were replaced in 1988 (Unit 2) and 2000 (Unit 1) based on industry and

site-specific operating experience that affected the integrity of the tubes. Along with the tube

material selection, several other design improvements were applied to the replacement steam

generators. In Unit 1, for example, stainless steel lattice grid assemblies and flat bar restraints

support the tubes, the minimum radius of the U-bend section of tubing was increased, and the

3-18
U-bend section of each tube was given a stress-relief heat treatment. In Unit 2, the tubes are

supported by stainless steel support plates with quatrefoil-shaped holes, a stainless steel flow

distribution baffle with octafoil-shaped holes, and stainless steel anti-vibration bars (AVBs) for

the U-bend sections. In both units the tubes were hydraulically expanded into the full thickness

of the tubesheet to minimize crevice corrosion and cracking. These tubesheet and tube

support features help prevent the accumulation of deposits and concentrated chemical

environments known to cause degradation of tubes with less corrosion resistance than the Alloy

690 tubes in the CNP steam generators.

Detailed steam generator inspection results were not included in the application. However, the

staff formally reviews all steam generator (SG) tube inspection reports submitted according to

the plant technical specifications. Although not performed as part of the license renewal

process, the NRC uses these reviews to support its evaluation of the LRA. All of the Unit 1

steam generators were inspected in May 2002 during the first refueling outage following'

replacement. Four tubes (two in SG 11 and one each in SGs 13 and 14) were plugged due to

unexplained signal changes in the bobbin coil voltage amplitude at five manufacturing burnish

mark indications between cold-leg tube supports. Babcock & Wilcox attributed the signal

change to a metallurgical structure change induced by the heat of the first operating cycle.

During the subsequent refueling outage in the fall of 2003, an inspection was performed on a

sample of tubes in SG 14. No tubes were plugged during the outage.-The only tube '

degradation reported for the Unit 1 steam generators is fan bar wear of one tube in SG 14 (11

percent through wall); no tubes have been plugged as a result.

The tubes in the Unit 2 steam generators have been inspected five times since installation in

1988. Including 1 tube plugged during the pre-operational inspection due to a manufacturing

flaw, a total of 15 tubes have been plugged in the four SGs (1 in SG 21, 6 in SG 23, and 4 each

in SGs 22 and 24). All of the 14 cases of tube plugging during inservice inspections occurred in

1994 and 1997, and all were the result of mechanical damage, foreign object wear, or tube

support plate wear. No tubes were plugged during the 2002 outage.

Staff Evaluation

In LRA Appendix B.1.31, the applicant stated that the Steam Generator Integrity Program is

consistent with the GALL AMP XI.M.19 (Steam Generator Tube Integrity), which is credited for

managing the aging effects of the steam generator tubes and secondary side internals needed

to maintain tube integrity. GALL AMP XI.M1 9 recommends preventative measures to mitigate'

degradation phenomena, assessment of degradation mechanisms, inservice inspection of

steam generator tubes to detect degradation, evaluation and plugging or repair, and leakage

monitoring to maintain the structural and leakage integrity of the pressure boundary. -

The applicant stated that the program is also based upon NEI 97-06, which includes'an

assessment of degradation mechanisms and considers operating experience from similar

steam generators to identify degradation mechanisms.: For each mechanism,'the EPRI

guidelines associated with NEI 97-06 define the inspection techniques, measurement

uncertainty, and the sampling strategy. The EPRI guidelines (TR-105714 and TR-102134)

associated with NEI 97-06 provide criteria for the qualification of personnel, specific techniques,

and the associated acquisition and analysis of data. This includes procedures, probe selection,

analysis protocols, and reporting'criteria. The performance criteria in NEI 97-06 pertain to

structural integrity, accident-induced leakage, and operational leakage. A steam generator

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program, as defined in NEI 97-06, includes guidance on assessment of degradation mechanisms, inspection, tube integrity assessment, maintenance, plugging, repair, leakage monitoring, and procedures for monitoring and controlling secondary-side and primary-side water chemistry. The applicant's Water Chemistry Control Program, based on EPRI's water

chemistry guidelines for PWRs, relies on monitoring and control of reactor water chemistry and

secondary water chemistry. The staff accepts the use of GALL AMP XI.M.1 9, NEI 97-06, and

EPRI water chemistry guidelines as the proper framework for managing the aging of steam

generator tubes and other components that can affect tube integrity.

RAIB.1.31-1

The applicant credited this program, all or in part, for managing the forms of aging other than

tube degradation listed below, but no components other than tubes are mentioned in the

program. Therefore, by letter dated June 30, 2004, the staff requested in RAI B.1.31-1 that the

applicant discuss how the Steam Generator Integrity Program manages aging of components other than tubes. The following examples were cited:

* material loss of carbon steel tube wrappers in treated water

* cracking of carbon steel tube wrappers in treated water

* material loss of stainless steel tube support plates and AVBs in treated water

* cracking of stainless steel tube support plates and AVBs in treated water

* material loss of carbon steel tube support plate stayrods and spacers in treated water

* cracking of carbon steel tube support plate stayrod nuts in treated water

* loss of mechanical closure integrity of tube support plate stayrod nuts in treated water

* material loss of nickel alloy tubes support plate stayrod washers and AVB retaining rings in treated water

* cracking of nickel alloy tubes support plate stayrod washers and AVB retaining rings in

treated water

* material loss of carbon steel lattice grid ring arch bars in treated water

* cracking of carbon steel lattice grid ring studs in treated water

* loss of mechanical closure integrity of carbon steel lattice grid ring studs in treated water

* material loss of stainless steel lattice grid bars, U-bend flat bars, and J-tabs in treated

water

* cracking of stainless steel lattice grid bars, U-bend flat bars, and J-tabs in treated water

With respect to the scoping aspect of RAI B.1.31-1, the applicant responded, in a letter dated

August 19, 2004, that because these components form the steam generator secondary side

tube support structure, they are included in GALL AMP XI.M1 9 under the Parameters Monitored

or Inspected element. This element states that the program detects flaws in tubing or the

degradation of secondary side internals needed to maintain tube integrity, and that degradation of steam generator internals is evaluated for corrective actions. The applicant noted that

Table 3.1.2-5 of the LRA indicates that these components perform the intended function of

providing structural and/or functional support for in-scope components (i.e., the steam

generator tubes), and are therefore subject to an AMR.

Regarding the aging management aspect of RAI B.1.31 -1, the applicant responded that CNP

Steam Generator Integrity Program includes secondary side visual inspections of the tubesheet

region, the tube support structures, the U-bend region, and the feedwater distribution system to

verify the overall structural integrity of the steam generator secondary side internals. These

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areas are visually inspected for evidence of degraded conditions, including component

deformation, material loss (erosion-corrosion, pitting, wear), cracking, foreign object damage,

loss of component integrity, and deposit buildup. If foreign objects are found, the Steam

Generator Integrity Program also prescribes corrective actions such as: metallurgical testing of

the part; categorization of probable causes, origin, and mitigation; and determination of the

need to expand inspections. If degraded conditions or foreign objects are found, the condition

is documented using the Corrective Action Program and the inspection scope in the area of

interest is expanded until the condition is bounded. In its response to RAI 3.1-4 dated August

11,2004, the applicant indicated that prior to the inspection of steam generator components, a

degradation assessment is completed to ensure that the inspections are adequately focused on

the expected degradation mechanisms. Visual examination of the secondary side internals is

based on the results of this assessment and include degraded conditions such material loss,

cracking, and loss of component integrity. In addition, in its follow-up response to RAI 3.1-3

dated October 18, 2004, the applicant stated that the interval for secondary side visual

inspections is no more than two operating cycles. The staff finds this response acceptable

because industry experience has shown that these actions are effective in managing aging of

secondary-side degradation and foreign material that could affect tube integrity.

RAI B. 1.31-2

The UFSAR Supplement for the Steam Generator Integrity Program is presented in LRA

Appendix A.2.1.34. The supplement discusses the integrity only of tubes and does not refer to

NEI 97-06. As discussed above, the Steam Generator Integrity Program is credited with

managing aging of other components that could affect tube integrity. Therefore, by letter dated

June 30, 2004, the staff requested in RAI B.1.31-2 that the applicant change the UFSAR

Supplement to reflect the full scope of the Steam Generator Integrity program and reference

the NEI 97-06 Steam Generator Program Guidelines. By letter dated August 19, 2004, the

applicant responded that it would revise Section A.2.1.34 revised for clarification as follows:

"The Steam Generator Integrity Program, which is based on guidance

provided in NEI 97-06, Steam Generator Program Guidelines, uses

nondestructive examination techniques to identify tubes that are defective and

need to be removed from service or repaired in accordance with the Technical

Specifications. In addition, the Steam Generator Integrity Program uses

visual inspections to manage the effects of aging on secondary side

internals needed to maintain steam generator tube integrity."

(NOTE: The text added for clarification in response to RAI B.1.31-2 is in bold italics.)

The staff accepts the revised UFSAR Supplement as an adequate summary. description of the

Steam Generator Integrity Program, as required by10 CFR 54.21(d).

Conclusion

On the basis of its review of the applicant's program, the staff finds the Steam Generator

Integrity Program is consistent with the GALL Report and will effectively manage aging of

steam generator tubes and secondary-side components. The staff therefore concludes that the

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steam generator tubes will perform their intended function according to the CLB during the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

In Appendix A to the LRA, the applicant provided the UFSAR Supplement required by

10 CFR 54.21 (d). The applicant will incorporate the information presented in Appendix A into

the UFSAR following the issuance of the renewed operating license. The staff reviewed the

information in Appendix A and determined that the information in the UFSAR Supplement

provides an adequate summary of the program activities with one exception which is addressed

by the staff evaluation of the applicant response to RAI 3.6-3 in Section 3.6.2.1.1 of this SER.

The staff reviewed the following sections of Appendix A:

* Section A.2.1.7 of the LRA for the Cast Austenitic Stainless Steel Evaluation Program * Section A.2.1.8 of the LRA for the Containment Leakage Rate Testing Program

* Section A.2.1.15 of the LRA for the Flow-Accelerated Corrosion Program

* Section A.2.1.17 of the LRA for the Inservice Inspection-ASME Section Xl, Inservice

Inspection, Subsection IWB, IWC, IWD Program

* Section A.2.1.19 of the LRA for the Inservice Inspection-ASME Section Xl, Inservice

Inspection, Subsection IWF Program

* Section A.2.1.23 of the LRA for the Non-EQ Inaccessible Medium-Voltage Cable

Program

* Section A.2.1.25 of the LRA for the Non-EQ Insulated Cables and Connections Program * Section A.2.1.30 of the LRA for the Reactor Vessel Internals Plates, Forgings, Welds,

and Bolting Program

* Section A.2.1.31 of the LRA for the Reactor Vessel Internals Cast Austenitic Stainless

Steel Components Program

* Section A.2.1.33 of the LRA for the Small Bore Piping Program

* Section A.2.1.34 of the LRA for the Steam Generator Integrity Program

* Section A.2.2.3 of the LRA for the Environmental Qualification of Electrical Components

Program

The staff reviewed these sections and determined that the information in the UFSAR

Supplements adequately summarizes the program activities. The staff finds these sections of

the UFSAR Supplements sufficient.

On the basis of its audit, the staff finds that those programs for which the applicant claimed

consistency with the GALL Report are indeed consistent with the AMPs described in the GALL

Report. The audit and review report documents the details of this effort.

The staff concludes that for the AMPs listed above, the applicant has demonstrated that it will

adequately manage the effects of aging so that the intended functions of SCs 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).

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

Enhancements ..

In Appendix B to the LRA, the applicant indicated that the following AMPs are/will be consistent

with the GALL Report with exceptions and/or enhancements:

* Boric Acid Corrosion Prevention Program

* Buried Piping Inspection Program

* -Control Rod Drive Mechanism and Other Vessel Head Penetration Inspection Program

* Diesel Fuel Monitoring Program

* Fire Protection Program

* Fire Water System Program

* Inservice Inspection-ASME Section Xl, Inservice Inspection, Subsection IWE Program

* Inservice Inspection-ASME Section Xl, Inservice Inspection, Subsection IWL Program

* Non-EQ Instrumentation Circuits Test Review Program

* Reactor Vessel Integrity Program

* -Service Water System Reliability Program

* -Structures Monitoring-Structures Monitoring Program

* Structures Monitoring-Crane Inspection Program

* Structures Monitoring-Masonry Wall Program

* Water Chemistry Control-Primary and Secondary Water Chemistry Control Program

* Water Chemistry Control-Closed Cooling Water Chemistry Control Program

* Fatigue Monitoring Program

For AMPs that the applicant claimed are consistent with the GALL Report with exceptions or

enhancements, the staff performed an audit to verify that those attributes or features of the

program for which the applicant claimed consistency with the GALL Report are indeed

consistent. Furthermore, the staff reviewed the exceptions or enhancements and its

justification to determine whether the AMP, with the exceptions or enhancements, remains

adequate to manage the aging effects for which it is credited. The staff documented this effort

in its audit and review report. The staff also reviewed the exceptions or enhancements to the

GALL Report to determine whether they are acceptable. The following sections document the

results of the staff's audit and reviews.

3.0.3.2.1 Boric Acid Corrosion Prevention

Summary of Technical Information In the Application

Section B.1.4, "Boric Acid Corrosion Prevention," of the LRA discusses the applicant's Boric

Acid Corrosion Prevention Program. The applicant stated that the program will be consistent

with GALL AMP Xl.M1 0, "Boric Acid Corrosion," after the program scope is expanded to

address electrical components subject to boric acid leakage. The applicant credited this AMP

with managing the aging of carbon steel and LAS SCs or electrical components onto which

borated water may leak. -The enhancements to this AMP are specified in Commitment #4 in

Appendix A of-this SER.:

The applicant developed and implemented this program to meet Generic Letter (GL) 88-05,

"Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR

Plants," and to monitor the condition of the RCS pressure boundary components for boric acid

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leakage. The program identifies ferritic steel components within the RCS that are susceptible

to corrosion from boric acid leakage and provides for visual inspection of these components

and their adjacent SCs. The applicant reviewed its condition reports (CRs) and determined that

most plant operating events involving the Boric Acid Corrosion Prevention Program involved

minor leakage that was corrected before component damage occurred. The applicant also

reviewed an NRC inspection report which concluded that the CNP program meets the

requirements of GL 88-05.

The CNP has experienced heat exchanger flange carbon steel bolt degradation as a result of

boric acid corrosion caused by boric acid leakage at bolted joints. The applicant detected the

degradation by visual examination and replaced the bolting with stainless steel bolts.

Staff Evaluation

RAI B.1.4-1

The applicant indicated that after widening the program scope to include electrical components,

the program will be consistent with the GALL Report. However, since the scope of the program

described in LRA Section B.1.4 does not mention any specific systems and their locations, the

staff was not sure that this program includes all systems and components, inside and outside

the containment, which may be subject to boric acid degradation as leakage sources or as SCs

adjacent to leakage sources. Hence, a clarification was sought through RAI B.1.4-1. This RAI

also asked the applicant to provide information regarding provisions in Boric Acid Corrosion

Program for inspecting, detecting, or monitoring degradation of SCs due to boric acid leakage

and provisions for inspecting, detecting, or monitoring boric acid leakage in inaccessible

locations and areas covered by external insulation surfaces.

The applicant responded in its letter dated August 19, 2004, that the Boric Acid Corrosion

Prevention Program applies to portions of systems and structures, both inside and outside of

containment, that are subject to an AMR. LRA Sections 3.1 to 3.6 list these SSCs as the

reactor pressure vessel (RPV) and control rod drive mechanism (CRDM) pressure boundary,

Class 1 piping, valves, and reactor coolant pump, pressurizer, steam generator, containment

spray system, containment isolation system, ECCS, containment equalization/hydrogen

skimmer (CEO) system, chemical and volume control (CVCS), fire protection (FP) system,

nonsafety related systems and components affecting safety related systems, containment,

auxiliary building, structural commodities such as heating, ventilation, and air conditioning

(HVAC) duct supports and instrument line supports, and electrical connectors.

The applicant further stated that on-going boric acid corrosion inspection and evaluation

commitments made in support of current operations, including those made in response to GL

88-05, will be carried forward through the period of extended operation. When leakage is

detected, the leakage path is followed to identify the source and all affected components along

the path, including locations covered by insulation. Since the applicant has clarified the scope

of this AMP and provided the information regarding inspecting, detecting, or monitoring

degradation of SCs due to boric acid leakage, including areas covered by external insulation

surfaces, RAI B.1.4-1 is closed.

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RAI B. 1.4-2

Operating Experience. With regard to operating experience, the LRA states that the program

continues to be improved based on operating experience, and program revisions have -.

incorporated lessons learned from CRs and industry guidance. To ensure that the program has

been revised appropriately on a continual basis considering operating experience, especially

the Davis-Besse vessel head degradation and the CRDM penetration cracking event, the staff

issued RAI B.1.4-2. RAI B.1.4-2 also requested the applicant to discuss the implementation of

corrective actions in the program to prevent the recurrence of degradation caused by boric acid

leakage, as required by GL 88-05.

The applicant responded as follows in a letter dated August 19, 2004:

The Control Rod Drive Mechanism and Other Vessel Head Penetration

Inspection Program continues to be improved based upon experience, as

evidenced by program improvements that incorporate 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

NRC Order EA-03-009 and its successors.

This response has clarified the scope of this AMP. Although components of the RPV and

CRDM pressure boundary are listed in LRA Section 3.1 as within the scope of Boric Acid

Corrosion Prevention Program, vessel head degradation and the CRDM penetration cracking,

which were directly addressed by Bulletin 2001-01, "Circumferential Cracking of Reactor

Pressure Vessel Head Penetration Nozzles," Bulletin 2002-01, "Reactor Pressure Vessel Head

Degradation and Reactor Coolant Pressure Boundary Integrity," Bulletin 2002-02, "Reactor

Pressure Vessel Head and Vessel Head Penetration Nozzle Inspection Programs," and NRC

Order EA-03-009, "Issuance of Order Establishing Interim Inspection Requirements for Reactor

Pressure Vessel Heads at Pressurized Water Reactor," and its successors, are outside the

scope of this program. The Control Rod Drive Mechanism and Other Vessel Head Penetration

Inspection Program specifically manages vessel head degradation and the CRDM penetration

cracking. SER Section 3.0.3.2 contains an evaluation of this program, including issues such as

lessons learned from the Davis-Besse vessel head degradation and the CRDM penetration

cracking discussed in Bulletins 2001-01,-2002-01, 2002-02, and NRC Order EA-03-009 and its

successors.

Bulletin 2002-01 also addresses RCPB integrity in general. On July 29, 2003, the NRC issued

Regulatory Issue Summary (RIS) 2003-13, "NRC Review of Responses to Bulletin 2002-01,

'Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary

Integrity."' This RIS concludes that licensees were complying with the technical specification

requirements on RCS leakage and the ASME Code requirements on visual inspection for leaks

during system pressure testing. However, the RIS also points out the weaknesses in the

current boric acid corrosion control and ASME Section Xl inspection programs and suggests

steps for licensees to strengthen their inspection programs to address potential cracking and

leakage in material susceptible to primary water stress corrosion cracking (PWSCC).

Experience at a number of plants in recent years has shown that components made of Alloy

600/82/182 materials are susceptible to PWSCC. The applicant addressed the PWSCC issue

by creating a new plant-specific program Alloy 600 Aging Management Program to manage

aging effects of Alloy 600/82/182 and Alloy 690/52/152 materials in RCS components. Section

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3.0.3.3 of this SER provides the staff evaluation and acceptance of the Alloy 600 Aging

Management Program.

As mentioned above, the Control Rod Drive Mechanism and Other Vessel Head Penetration

Inspection Program specifically manags the CRDM penetration (Alloy 600/82/182) cracking.

The staff considers the applicant's response to Bulletin 2002-01 appropriate based on the 1990

NRC inspection report, which concluded that the Boric Acid Corrosion Prevention Program

meets the guidance in GL 88-05; the RIS on Bulletin 2002-01 responses, which concludes that

licensees were complying with the technical specification requirements on RCS leakage and the

ASME Code requirements; the applicant's creation of Alloy 600 Aging Management Program,

which is designed to manage the aging effects of Alloy 600/82/182 and Alloy 690/52/152

materials in RCS components; and the applicant's improved measures on operations

walkdowns following a unit shutdown while RCS temperature and pressure are near normal

operating condition.

Other recent NRC generic communications, which are related to the boric acid corrosion of

susceptible systems and components, include Bulletin 2003-02, "Leakage from Reactor

Pressure Vessel Lower Head Penetrations and Reactor Coolant Pressure Boundary Integrity"

and 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." The responses to these two Bulletins are still under staff review. The applicant

stated in its August 19, 2004 response to the RAls for this LRA that, "[clonsistent with the first

and second principles of license renewal, on-going boric acid corrosion inspection and

evaluation commitments made in support of current operations...will be carried forward through

the period of extended operation." It will carry forward any changes to the Boric Acid Corrosion

Prevention Program resulting from the conclusions of these reviews. Therefore, the first part of

RAI B.1.4-2 is closed.

In response to the second part of this RAI, concerning the implementation of corrective actions

in the Boric Acid Corrosion Prevention Program, the applicant provided, in addition to the

replacement of the corroded heat exchanger flange carbon steel bolts with the stainless steel

bolts discussed in LRA Section B.1.4, three more examples of corrective actions. They are (1) -

the replacement of carbon steel packing studs on valves within the RCPB, (2) the identification

of components within the RCS that are susceptible to corrosion damage and the use of suitable

corrosion resistant materials or the application of protective coatings/claddings, and (3) the

review of training programs and procedures to ensure that adequate guidance is given

regarding RCPB leakage and corrosion concerns. Therefore, RAI B.1.4-2 is closed.

Hence, the staff found the applicant's program scope to be acceptable. After expanding the

Boric Acid Corrosion Prevention Program scope to include electrical components as listed in

LRA Table 3.6.1, "Electrical Components, NUREG-1801 Vol. 1," this AMP will be consistent

with the GALL Report. Therefore, the staff determines that the program will provide reasonable

assurance that age related degradation will be managed during the period of extended

operation.

The staff confirmed the applicant's claim that the Boric Acid Corrosion Prevention Program is

consistent with the GALL Report. In addition, the staff determined that the applicant properly

applied the GALL program to its facility.

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UFSAR Supplement

In Appendix A, Section A.2.1.4, to the LRA, the applicant provided the UFSAR Supplement for

the Boric Acid Corrosion Prevention Program. The staff reviewed this section and determined

that the information in the UFSAR Supplement adequately summarizes 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 this AMP is

consistent with the GALL Report. The staff finds that the applicant has demonstrated that it will

adequately manage the effects of aging so that the intended functions of SCs 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).

Therefore, the staff concludes that the applicant has identified and taken, or will take, actions to

manage the effects of aging during the period of extended operation on the functionality of SCs

subject to this AMR, such that there is reasonable assurance that the applicant will continue to

conduct the activities authorized by a renewed license in accordance with the CLB, as required

by 10 CFR 54.29(a).

The staff reviewed the operating experience associated with the AMPs that are consistent with

the GALL Report as listed above. The staff concluded that the applicant adequately considered

operating experience associated with the AMPs.

3.0.3.2.2 Buried Piping Inspection

Summary of Technical Information in the Application

Section B.1.6, "Buried Piping Inspection," of the LRA describes the applicant's Buried Piping

Inspection Program. In the LRA, the applicant stated that it will initiate this new program before

the period of extended operation. This program will be consistent, with exception, with GALL-.

AMP XI.M34, "Buried Piping and Tanks Inspection.' The applicant stated that the Buried Piping

Inspection Program will include (1) preventive measures to mitigate corrosion and (2)

inspections to manage the effects of corrosion on the pressure-retaining capability of buried

carbon steel components.- The applicant also stated that it will implement preventive measures

in accordance with standard industry practice for maintaining external coatings and wrappings.

It will inspect buried components when excavating them during maintenance.- The

implementation and enhancement of the Buried Piping Inspection Program are listed as

Commitments #5 and #42 in Appendix A of this SER.

Staff Evaluation _

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort.

Furthermore, the staff reviewed the exception and its justifications to determine whether the

AMP, with the exception, remains adequate to manage the aging effects for which it is credited.

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In Section B.1 .6 of Appendix B to the LRA, the applicant stated that the Buried Piping

Inspection Program will be consistent with GALL AMP XL.M34 with one exception. The Buried

Piping Inspection Program takes exception to the Detection of Aging Effect program element, in

that the buried tanks and piping will be inspected only when excavated during maintenance

activities, rather than based on periodic inspection with a scheduled inspection frequency as

recommended by the GALL Report.

The staff reviewed the applicant's operating experience with excavations. Based on its review,

the staff finds that the frequency of excavating buried components for maintenance activities

will be sufficient to provide reasonable assurance that the applicant will identify the effects of

aging before the loss of intended function. Problems discovered in piping require evaluation

and reporting under the plant's Corrective Action Program. Excavating such components solely

to perform inspections could pose undue risk of damage to protective coatings. The staff finds

this exception to be acceptable.

Operating Experience The applicant stated in the LRA that multiple excavations at the site

have provided some plant-specific operating experience, even though the Buried Piping

Inspection Program is new. The piping and valves that were uncovered and inspected were of

the same material (carbon steel) or a less corrosion-resistant material (i.e., Lake Township

water and station drainage piping) than the buried piping and tanks in the scope of this

program. The review did not identify catastrophic failures of similar components. Failures of

fuel oil tanks and piping have been limited to small leaks resulting from localized corrosion,

such as pitting.

The applicant also stated that it expects future inspection results from similar excavations to

indicate the condition of fuel oil system components. It will consider industry and plant-specific

operating experience in the development of this program, as appropriate.

The staff reviewed the documentation for multiple excavations performed at the site for several

maintenance activities, such as repairs to Lake Township water, fire protection, and station

drainage piping. These excavations indicate that corrosion has not been a problem. The staff

also reviewed the site soil characteristics as presented in the applicant's UFSAR Table 5.2-2

and basis documents. The staff finds that soil acidity values are close to the neutral pH value

of 7.0. In addition, the lowest soil resistivity value was 21,000 Ohm-cm, and values as high as

727,000 Ohm-cm have been recorded. These relatively high soil resistivity values mitigate

concerns with the corrosion of buried structures.

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 Buried Piping Inspection Program will

adequately manage the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.6 of Appendix A to 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 adequately summarizes the program activities. The staff

finds this section of the UFSAR Supplement sufficient.

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Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

attributes of the program for which the applicant claimed consistency with the GALL Report are

indeed consistent with the GALL Report. In addition, the staff has reviewed the exception to the

GALL Report and finds that the applicant has demonstrated that it will adequately manage the

effects of aging so that the intended functions of SCs 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 Control Rod Drive Mechanism and Other Vessel Head Penetration Inspection

Summary of Technical Information in the Application

Section B.1.9 of Appendix B to the LRA discusses the Control Rod Drive Mechanism and Other

Vessel Head Penetration Inspection Program. The applicant stated that the Control Rod Drive

Mechanism and Other Vessel Head Penetration Inspection Program is an existing program at

CNP which manages the cracking of nickel-based alloy reactor vessel head (RVH) penetrations

exposed to borated water. According to the applicant, continued implementation of this

program will ensure that the pressure boundary function is maintained during the period of

extended operation. The applicant stated that it will use the Inservice Inspection - ASME

Section Xl, Subsection IWB, IWC, and IWD and Water Chemistry Control Programs in

conjunction with this program to manage cracking of the RVH penetrations. This program

manages primary water stress-corrosion cracking (PWSCC) of high nickel-alloy RVH

penetrations. The applicant stated that the Control Rod Drive Mechanism and Other Vessel

Head Penetration Inspection Program is consistent with GALL AMP XI.M1 1, with the exception

that the Detection of Aging Effects is based on responses to NRC Bulletins 2002-01, "Reactor

Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity," dated

March 18, 2002, and 2002-02, "Reactor Pressure Vessel Head and Vessel Head Penetration

Nozzle Inspection Programs," dated August 9, 2002, instead of GL 97-01, "Degradation of

Control Rod Drive Mechanism and Other Vessel Closure Head Penetrations," dated April 1,

1997.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the Control Rod Drive Mechanism

and Other Vessel Head Penetration Inspection Program to determine if the program

demonstrates that the effects of aging will be adequately managed so that the intended

functions of SCs will be maintained consistent with the CLB for the period of extended

operation.

Generic Letter 97-01 provides the staff's original basis for inspecting Alloy 600 RVH penetration

nozzles in U.S.PWRs. Between November 2000 and April 2001, subsequent to the issuance of

GL 97-01, RCPB leakage was identified from the RVH penetration nozzles of four U.S. PWRdesign light-water reactor facilities. Supplemental examinations of the degraded nozzles

indicated the presence of circumferential cracks in four of the CRDM nozzles. These cracks

initiated from the outer surface of the nozzle, either in the associated J-groove weld or heataffected zone, and not from the inside surface of the nozzle, as was assumed in the industry

3-29
responses to GL 97-01. These cracks penetrated through the nozzles and were initially

identified as circumferential cracking in U.S. RVH penetration nozzles. In NRC Bulletin 2001-

01, the staff discusses the generic safety significance and impacts of these cracks on RVH

penetration nozzles and recommends that enhanced visual examination or volumetric

examination methods be used for the inspection of RVH nozzles.

In March 2002, during a refueling outage at the Davis-Besse Nuclear Power Station, the

licensee for the plant reported the occurrence of reactor coolant leakage from RVH penetration

nozzles. As a result of followup evaluations of the reactor coolant leakage, the licensee

reported that the leakage resulted in significant boric-acid-related wastage of the RVH. The

wastage affected the entire thickness of the RVH with the exception of the RVH cladding. On

March 18, 2002, the NRC issued Bulletin 2002-01 to owners of PWR designs, 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 to address additional technical issues resulting from the Davis-Besse event. In NRC

Bulletin 2002-02, the staff specifically suggests performing further augmented inspections,

more comprehensive than those suggested in NRC Bulletin 2001-01, on RVH penetration

nozzles. On February 11, 2003, the staff issued Order EA-03-009, issuance of Order

Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at

Pressurized Water Reactors," to further define to the licensees the frequency and extent of

inspection of the RPV head nozzles. On August 21, 2003, the staff issued NRC Bulletin

2003-02, "Leakage from Reactor Pressure Vessel Lower Head Penetrations and Reactor

Coolant Pressure Boundary Integrity," to advise licensees that they may need to supplement

RPV lower head inspections with additional measures to assure the detection of the RCPB

leakage. On February 20, 2004, the staff issued First Revised NRC Order EA-03-009 to modify

the inspection requirements for RPV heads at PWRs.

The applicant stated that it developed the Control Rod Drive Mechanism and Other Vessel

Head Penetration Inspection Program based on the events that resulted in the reactor vessel

closure head at Davis-Besse. The applicant also stated that it will continue to refine the

program as the requirements resulting from the event at Davis-Besse evolve.

The staff assessed the program against the 10 AMP elements that are described in the GALL

Report. The applicant stated that for those AMPs that are comparable to the programs

described in the GALL Report, it presented the program discussion in the following format:

* program description

* GALL Report consistency

* exceptions to the GALL Report

* enhancements

* operating experience

* conclusion

The applicant also stated that the corrective actions, confirmation process, and administrative

controls are all common to the AMPs. Therefore, further discussion is not necessary and not

included in the description of the individual programs. The staff review included these three

elements, and the results are provided below.

3-30
Program Description The applicant stated that the Control Rod Drive Mechanism and Other

Vessel Head Penetration Inspection Program is an existing program at CNP. It is comparable

to the program described in GALL AMP XI.M1 1, 'Nickel-Alloy Nozzles and Penetrations." The

applicant stated that the program manages cracking of nickel-based alloy RVH penetrations

exposed to borated water. This program manages PWSCC of high nickel-alloy RVH

penetrations.-

The applicant stated that the Control Rod Drive Mechanism and Other Vessel Head Penetration

Inspection Program is comparable to the program described in the GALL Report, with the'

exception that the program is based on responses to NRC Bulletins 2002-01 and 2002-02,

instead of GL 97-01.

RAI B.1.9.2-1

The program description submitted in the application does not include references to NRC

Bulletin 2003-02; NRC Order EA-03-009, dated February 11,2003; and the First Revised NRC

Order EA-03-009, dated February 20, 2004, as part of the CLB for the Control Rod Drive

Mechanism and Other Vessel Head Penetration Inspection Program. Therefore, in RAI

B.1.9.2-1, the staff requested the following action of the applicant:

Update its Program Description to include reference to NRC Bulletin 2002-01,

2002-02, 2003-02, Order EA-03-009 dated February 11, 2003 and the First

Revised NRC Order EA-03-009 dated February 20, 2004.

In its letter dated August 11, 2004, the applicant responded to RAI B.1.9.2-1 which references

documentation that describes the Control Rod Drive Mechanism and Other Vessel Head

Penetration Inspection Program. The applicant stated that the issue of RPV head inspections,

which the Control Rod Drive Mechanism and Other Vessel Head Inspection Program

addresses, is the subject of the First Revised NRC Order EA-03-009 and is an evolving issue

under 10 CFR Part 50,-T Domestic Licensing of Production and Utilization Facilities." The

applicant noted that the obligations to satisfy the First Revised NRC Order EA-03-009

supercede the obligations to satisfy NRC Order EA-03-009 and commitments made in response

to NRC Bulletins 2002-01 and 2002-02. The applicant will continue ongoing inspection and

evaluation activities to comply with the First Revised NRC Order EA-03-009 and successor

orders or regulations, and order conditions thereto, through the period of extended operation.

The applicant noted that this is consistent with the second principle of license renewal, as

discussed in the Statements of Consideration (SOC) for the final rule for 10 CFR Part 54, which

states that 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: The applicant also

stated that the Alloy 600 Aging Management Program will address the commitments made in

response to NRC Bulletin 2003-02 which apply to lower vessel head penetrations (VHPs).

Consistent with the second principle of license renewal, the applicant will continue ongoing

commitments made in response to NRC Bulletin 2003-02 through the period of extended

operation.

The issue raised in NRC Bulletin 2003-02 related to cracking of Alloy 600 welds in lower vessel

head penetration nozzles and the issue related to cracking of other reactor coolant pressure

boundary nickel alloy components (other than those used in the fabrication of upper vessel

head penetration nozzles) are emerging issues that are being investigated by the NRC. The

3-31
staff is currently evaluating the need to enact requirements related to augmented inspections of

nickel alloy components in the reactor coolant pressure boundaries of PWRs and the ability of

these inspections to detect cracking in and leakage from these components. These current

operating issues raise questions about the capability of these components to perform their

intended functions during the current license term. The Commission has recognized that aging issues could arise during the license renewal review that raise questions about the capability of

structures or components to perform their intended functions during the current term of

operation, and provided for such issues in 10 CFR 54.30, which requires that such issues be

addressed under the current license, rather than as part of the license renewal review.

Therefore, this issue is beyond the scope of this license renewal review, pursuant to

10 CFR 54.30(b).

However, since this issue might not be resolved prior to issuance of the renewed operating licenses for CNP, Units 1 and 2, the applicant has committed to two license renewal

commitments for the Alloy 600 Aging Management Program to address the need to implement additional augmented inspection requirements for nickel alloy components in the CNP reactor

coolant pressure boundaries:

Commitment #1 - "The Alloy 600 Aging Management Program will be

implemented prior to the period of extended operation. This program will

manage aging effects of Alloy 600/690 components and Alloy 52/152 and 82/182

welds in the reactor coolant system that are not addressed by other aging

management programs. This program will detect primary water stress corrosion

cracking prior to the loss of component intended function by using the

examination and inspection requirements specified in American Society of

Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section Xl."

Commitment #2 - "The Alloy 600 Aging Management Program commitment will

also be revised to indicate that an inspection plan will be submitted for staff

review and approval 3 years prior to the period of extended operation to

determine if the program demonstrates an ability to manage the effects of aging pursuant to 10 CFR 54.21 (a)(3)."

The staff's evaluation of the inspection plan, when submitted for review and approval, will

include an assessment of whether the current ASME Code requirements and any supplemental augmented inspection requirements that may be enacted by the staff for nickel alloy components are sufficient to ensure aging management under 10 CFR 54.21 (a) or whether

additional actions will be necessary under 10 CFR 54.21(a). Based on this assessment, the

staff concludes that the applicant's obligations to comply with the First Revised NRC Order

EA-03-009 and two additional license renewal commitments for the Alloy 600 Aging Management Program will be sufficient to ensure management of cracking in the nickel alloy CRDM penetration nozzles and other upper and lower head penetration nozzle components and associated welds, as required by 10 CFR 54.21 (a).

Based upon the applicant's response to RAI B.1.9.2-1, the staff concludes that the applicant's obligation to comply with the First Revised Order EA-03-009 along with the two commitments

discussed above ensures the structural integrity of the components during the period of

extended operation. Therefore, the staff concludes that RAI B.1.9.2-1is closed.

3-32
Preventive Actions The applicant stated in the program description that it uses the Inservice

Inspection - ASME Section Xl and Water Chemistry Control Programs in conjunction with this

program to manage cracking of the RVH penetrations.

RAI B. 1.9.2-2

The applicant did not state that material replacement is an available option to prevent or

mitigate the potential for PWSCC.- Therefore, in RAI B.1.9.2-2, the staff requested the'following

action of the applicant:

The applicant is requested to include a preventive action section in its program to

include examples of actions taken or to be taken to prevent ARDMs, the types of

materials considered for replacement, and also include compliance with the First

Revised NRC Order EA-03-009 or successor regulatory requirements.

In its letter dated August 11, 2004, the applicant's response to RAI B.1.9.2-2 stated the Control

Rod Drive Mechanism and Other Vessel Head Penetration Inspection Program is consistent

with, but includes an exception to, the' program attributes described in the GALL Report,

Section XI.M1 1. Details of compliance with the GALL'Report, Section XI.M1 1, specifies the

following preventive actions:

Preventive measures to mitigate PWSCC are in accordance with EPRI

guidelines in TR-105714. The program description and the evaluation and

technical basis of monitoring and maintaining reactor water chemistry are

presented in NUREG-1801, Chapter XI.M2, Water Chemistry..

The applicant stated the Primary and Secondary Water Chemistry Control Program provides

preventive measures to minimize the potential for cracking of nickel-based alloy nozzles. With

the inclusion'of enhancements, this program, which is described in LRA Section B.1.40.1, will

be consistent with the GALL Report, Section XI.M2.

In its response, the applicant stated that the Control Rod Drive Mechanism and Other Vessel

Head Penetration Inspection Program is designed to manage the effects of PWSCC.:- The

program does not preclude material replacement as an option to prevent or mitigate PWSCC.

When a part is replaced, appropriate materials for the proposed replacement (such as Alloy 690

and 52/152 weld materials) are selected in accordance with good engineering practice.

The applicant stated that it will carry forward its obligations to comply with the First Revised --

Order EA-03-009 and successor orders or regulations, and order conditions thereto, through

the period of extended operation. This is consistent with the SOC for the final rule under

10 CFR Part 54.

The staff concludes that the implementation of the applicant's obligation to comply with First

Revised Order EA-03-009 referenced in the response to RAI B.1.9.2-2 will ensure that the

appropriate changes will be made (i.e:, those that assure-the structural integrity of the RVH

penetrations during the extended period of extended operation). Therefore,-the staff considers

RAI B.1.9.2-2 closed. -

3-33
RAI B. 1.9.2-3

Parameters Monitored or Inspected The staff reviewed this element and concluded that the

applicant must provide additional information. Therefore, in RAI B.1.9.2-3, the staff requested

the following actions of the applicant:

The applicant stated that the program monitors the effects of PWSCC on the

intended function of the CRDM and other Alloy 600 head penetrations by

detection and sizing of cracks and coolant leakage by ISI. The program needs

to state that monitoring will be in accordance with the First Revised Order

EA-03-009 dated February 20, 2004 and also identify specifically how cracks will

be sized.

In its letter dated August 11, 2004, the applicant responded to RAI B.1.9.2-3 that the site

documentation describes the Control Rod Drive Mechanism and Other Vessel Head

Penetration Inspection Program. The issue of RPV head inspections, which the Control Rod

Drive Mechanism and Other Vessel Head Inspection Program addresses, is the subject of the

First Revised NRC Order EA-03-009 and is an evolving 10 CFR Part 50 issue. References 1

through 5 of the applicant's response to RAI B.1.9.2-1 provide the l&M CLB, which applies to

implementation of the requirements of the First Revised NRC Order EA-03-009, including

monitoring requirements and flaw characterization. The applicant will continue ongoing

inspection and evaluation activities to comply with the First Revised NRC Order EA-03-009 and

successor orders or regulations, and order conditions thereto, through the period of extended

operation. The applicant noted that this is consistent with the second principle of license

renewal, as discussed in the SOC for the final rule for 10 CFR Part 54, which states that 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.

The applicant also stated that the Control Rod Drive Mechanism and Other Vessel Head

Penetration Inspection Program monitors the cracking of nickel-based alloy nozzles with partial

penetration welds in the reactor vessel closure head. The applicant stated that it will continue

ongoing monitoring activities to comply with First Revised NRC Order EA-03-009 and successor

orders or regulations, and order conditions thereto, through the period of extended operation.

The applicant stated that this is also consistent with the SOC for the final rule for

10 CFR Part 54.

The staff concludes that the applicant's obligations to comply with the First Revised Order EA03-009 and successor orders or regulations referenced in the response to RAI B.1.9.2-3 will

ensure that the appropriate changes will be implemented (i.e., those that assure the structural

integrity of the RVH penetrations during the extended period of extended operation).

Therefore, the staff considers RAI B.1.9.2-3 closed.

RAI B. 1.9.2-4

Detection of Aging Effects The GALL Report identifies that the scope and schedule of

inspections, including the leakage detection system, is based on NRC GL 97-01. The applicant

stated that the CNP program is based on responses to NRC Bulletins 2002-01 and 2002-02,

instead of NRC GL 97-01. Therefore, in RAI B.1.9.2-4, the staff requested the following action

of the applicant:

3-34
Update the Control Rod Drive Mechanism and Other Vessel Head Penetration -

Inspection Program to reference Bulletin 2002-03; NRC Order EA-03-009, dated

February 11, 2003; and the First Revised NRC Order EA-03-009, dated February 20,

2004, as the basis for the scope and schedule of the inspections. In addition, the

program must identify any enhanced leakage detection methods used for detecting

small leaks during plant operation, as well as programs and models used to assess

PWSCC susceptibility for CNP.

In its letter dated August 11, 2004, the applicant responded to RAI B.1.9.2-4 that the site

documentation contains details of the Control Rod Drive Mechanism and Other Vessel Head

Penetration Inspection Program. The issue of RPV head inspections, which the Control Rod

Drive Mechanism and Other Vessel Head Inspection Program addresses, is the subject of the

First Revised NRC Order EA-03-009 and is an evolving 10 CFR Part 50 issue. The applicant

stated that References 1 through 5 for its response to RAI B.1.9.2-1 provide the CLB relevant to

the implementation of the requirements of the First Revised NRC Order EA-03-009. The

applicant will continue ongoing inspection and evaluation activities to comply with the First

Revised NRC Order EA-03-009 and successor orders or regulations, and order conditions

thereto, through the period of extended operation. The applicant noted that this is consistent

with the second principle of license renewal, as discussed in the SOC for the final rule for

10 CFR Part 54, which states that 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. The applicant also stated that the CNP technical specifications document the'operability

requirements for RCS leakage detection systems. The applicant identified the Alloy 600 Aging

Management Program as managing the aging effects for bottom-mounted instrumentation

(BMI) nozzles. It will continue commitments made in response to Bulletin 2003-02 through the

period of extended operation.

The issue raised in NRC Bulletin 2003-02 related to cracking of Alloy 600 welds in lower vessel

head penetration nozzles and the issue related to cracking of other reactor coolant pressure

boundary nickel alloy components (other than those used in the fabrication of upper vessel

head penetration nozzles) are emerging issues that are being investigated by the NRC. The,

staff is currently evaluating the need to enact requirements related to augmented inspections of

nickel alloy components in the reactor coolant pressure boundaries of PWRs and the ability 'of

these inspections to detect cracking in and leakage from these components. These current

operating issues raise questions about the capability of these components to perform their ' -

intended functions during the current license term. The Commission has recognized that aging

issues could arise during the license renewal review that raise questions about the capability of

structures or components to perform their intended functions during the current term of

operation, and provided for such issues in 10 CFR 54.30, which requires that such issues be

addressed under the current license, rather than as part of the license renewal review.

Therefore, this issue is beyond the scope of this license renewal review, pursuant to

10 CFR 54.30(b). -

However, since this issue might not be resolved prior to issuance of the renewed operating

licenses for D.C Cook, Unit 1-and 2, the applicant has committed to the following two license

renewal commitments for~the Alloy 600 Aging Management Program to address the need to

implement additional augmented inspection requirements for nickel alloy components in the

CNP reactor coolant pressure boundaries:

3-35
Commitment #1 - "The Alloy 600 Aging Management Program will be

implemented prior to the period of extended operation. This program will

manage aging effects of Alloy 600/690 components and Alloy 52/152 and 82/182

welds in the reactor coolant system that are not addressed by other aging

management programs. This program will detect primary water stress corrosion

cracking prior to the loss of component intended function by using the

examination and inspection requirements specified in American Society of

Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code,

Section Xl."

Commitment #2 - "The Alloy 600 Aging Management Program commitment will

also be revised to indicate that an inspection plan will be submitted for staff

review and approval 3 years prior to the period of extended operation to

determine if the program demonstrates an ability to manage the effects of aging

pursuant to 10 CFR 54.21 (a)(3)."

The staff's evaluation of the inspection plan, when submitted for review and approval, will

include an assessment of whether the current ASME Code requirements and any supplemental

augmented inspection requirements that may be enacted by the staff for nickel alloy

components are sufficient to ensure aging management under 10 CFR 54.21 (a) or whether

additional actions will be necessary under 10 CFR 54.21 (a). Based on this assessment, the

staff concludes that the applicant's obligations to comply with the First Revised NRC Order

EA-03-009 and two additional license renewal commitments for the Alloy 600 Aging

Management Program will be sufficient to ensure management of cracking in the nickel alloy

CRDM penetration nozzles and other upper and lower head penetration nozzle components

and associated welds, as required by 10 CFR 54.21 (a).

Based upon the applicant's response to RAI B.1.9.2-4, the staff concludes that the applicant's

obligation to comply with the First Revised Order EA-03-009 along with the two commitments

discussed above ensures the structural integrity of the components during the period of

extended operation. Therefore, the staff concludes that RAI B.1.9.2-4 is closed.

RAI B. 1.9.2-5

Monitoring and Trending The GALL Report states that inspection schedules are based on the

susceptibility assessments in GL 97-01. Therefore, in RAI B.1.9.2-5, the staff requested the

following actions of the applicant:

Update B.1.9 to include a Monitoring and Trending element. The element should

include current inspection schedules and frequency of inspections based on any

findings of initial inspections, how inspection results are used to update

susceptibility models, and identify models that are used to evaluate crack growth

and flaw evaluations.

In its letter dated August 11, 2004, the applicant responded to RAI B.1.9.2-5 that the site

documentation contains details of the Control Rod Drive Mechanism and Other Vessel Head

Penetration Inspection Program. The issue of RPV head inspections, which the Control Rod

Drive Mechanism and Other Vessel Head Inspection Program addresses, is the subject of the

First Revised NRC Order EA-03-009 and is an evolving 10 CFR Part 50 issue. The applicant

3-36
stated that References 1 through.5 for its response to RAI B.1.9.2-1 provide the CLB relevant

to the implementation of the requirements of the First Revised NRC Order EA-03-009, including

inspection schedule and frequency requirements. The applicant will continue ongoing

inspection and evaluation activities to comply with the First Revised NRC Order EA-03-009 and

successor orders and regulations, and order conditions thereto, through the period of extended

operation. The applicant noted that this is consistent with the second principle of license

renewal, as discussed in the SOC for the final rule for 10 CFR Part 54, which states that 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.

The staff concludes that the applicant's obligations to comply with First Revised Order EA-03- -

009 and successor orders or regulations referenced in the response to RAI B.1.9.2-5 will'

ensure that the appropriate changes will be implemented (i.e., those that assure the structural

integrity of the RVH penetrations during the extended period of extended operation).

Therefore, the staff considers RAI B.1.9.2-5 closed.

RAI B. 1.9.2-6.

Acceptance Criteria The GALL Report states that any indication detected must be evaluated in

accordance with Section Xl of the ASME Code or other acceptable flaw evaluation criteria. To

verify the adequacy of the long-term inspection program and acceptance criteria and assess if

there have been significant changes since the applicant's response to NRC GL 97-01, the -

applicant must provide references to appropriate industry model revisions or provide updated

information on crack initiation and growth data and models used. Therefore, in RAI B.1.9.2-6,

the staff requested the following actions of the applicant:

Update B.1.9 to include an Acceptance Criteria element and to provide updatedinformation on crack initiation and crack growth data and models used.

Additionally, include references to the NRC Bulletins 2002-01, 2002-02, 2003-02,

Order EA-03-009 dated February 11, 2003, and the First Revised NRC Order

EA-03-009.

In its letter dated August 11, 2004, the applicant responded to RAI B.1.9.2-6 that the site

documentation contains details of the Control Rod Drive Mechanism and Other Vessel Head

Penetration Inspection Program. The issue of RPV head inspections, which the Control Rod

Drive Mechanism and Other Vessel Head Inspection Program addresses, is the subject of the

First Revised NRC Order EA-03-009 and is an evolving 10 CFR Part 50 issue. The applicant

stated that References 1 through 5 for its response to RAI B.1.9.2-1 provide its CLB relevant to

the implementation of the requirements of the First Revised NRC Order EA-03-009, including

acceptance criteria and updated information on crack initiation and growth data and models

used. The applicant will continue ongoing inspection and evaluation activities to comply with

the First Revised NRC Order EA-03-009 and successor orders or regulations, and order:

conditions thereto, through the period of extended operation. The applicant stated that this is:

consistent with the second principle of license renewal, as discussed in the Statements of

Consideration for the final rule for 10 CFR Part 54, which states that 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. The applicant also stated that the CNP Alloy 600 Aging

Management Program will address commitments made in response to NRC Bulletin 2003-02

3-37
which apply to lower VHPs. It will continue ongoing commitments made in response to NRC

Bulletin 2003-02 through the period of extended operation.

The issue raised in NRC Bulletin 2003-02 related to cracking of Alloy 600 welds in lower vessel

head penetration nozzles and the issue related to cracking of other reactor coolant pressure

boundary nickel alloy components (other than those used in the fabrication of upper vessel

head penetration nozzles) are emerging issues that are being investigated by the NRC. The

staff is currently evaluating the need to enact requirements related to augmented inspections of

nickel alloy components in the reactor coolant pressure boundaries of PWRs and the ability of

these inspections to detect cracking in and leakage from these components. These current

operating issues raise questions about the capability of these components to perform their

intended functions during the current license term. The Commission has recognized that aging

issues could arise during the license renewal review that raise questions about the capability of

structures or components to perform their intended functions during the current term of

operation, and provided for such issues in 10 CFR 54.30, which requires that such issues be

addressed under the current license, rather than as part of the license renewal review.

Therefore, this issue is beyond the scope of this license renewal review, pursuant to

10 CFR 54.30(b).

However, since this issue might not be resolved prior to issuance of the renewed operating

licenses for CNP, Units 1 and 2, the applicant has committed to the following two license

renewal commitments for the Alloy 600 Aging Management Program to address the need to

implement additional augmented inspection requirements for nickel alloy components in the

CNP reactor coolant pressure boundaries:

Commitment #1 - uThe Alloy 600 Aging Management Program will be

implemented prior to the period of extended operation. This program will

manage aging effects of Alloy 600/690 components and Alloy 521152 and 82/182

welds in the reactor coolant system that are not addressed by other aging

management programs. This program will detect primary water stress corrosion

cracking prior to the loss of component intended function by using the

examination and inspection requirements specified in American Society of

Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code,

Section Xl."

Commitment #2 - 'The Alloy 600 Aging Management Program commitment will

also be revised to indicate that an inspection plan will be submitted for staff

review and approval 3 years prior to the period of extended operation to

determine if the program demonstrates an ability to manage the effects of aging

pursuant to 10 CFR 54.21 (a)(3)."

The staff's evaluation of the inspection plan, when submitted for review and approval, will

include an assessment of whether the current ASME Code requirements and any supplemental

augmented inspection requirements that may be enacted by the staff for nickel alloy

components are sufficient to ensure aging management under 10 CFR 54.21 (a) or whether

additional actions will be necessary under 10 CFR 54.21 (a). Based on this assessment, the

staff concludes that the applicant's obligations to comply with the First Revised NRC Order

EA-03-009 and two additional license renewal commitments for the Alloy 600 Aging

Management Program will be sufficient to ensure management of cracking in the nickel alloy

3-38
CRDM penetration nozzles and other upper and lower head penetration nozzle components

and associated welds, as requir6d by 10 CFR 54.21 (a).

Based upon the applicant's response to RAI B.1.9.2-6, the staff concludes that the applicant's

obligation to comply with the First Revised Order EA-03-009 along with the two commitments

discussed above ensures the structural integrity of the components during the period of

extended operation. Therefore, the staff concludes that RAI B.1.9.2-6 is closed.

Corrective Actions The applicant stated that it implements the CNP quality assurance

procedures, review and approval process, and administrative controls in accordance with the

requirements of Appendix B to 10 CFR Part 50. The applicant stated that the CNP corrective

actions are consistent with the GALL Report. The staff considers this element to be acceptable

because it meets the requirements of Appendix B to 10 CFR Part 50 and the GALL Report.

Confirmation Process The applicant stated that it implements CNP procedures, review and

approval processes, and administrative controls in accordance with the requirements of

Appendix B to 10 CFR Part 50. The applicant also stated that the CNP confirmation process is

consistent with the GALL Report. The staff considers this element to be acceptable because it

meets the requirements of Appendix B to 10 CFR Part 50 and the GALL Report.

Administrative Controls The applicant stated that it implements the CNP quality assurance

procedures, review and approval processes, and administrative controls in accordance with the

requirements of Appendix B to 10 CFR Part 50. In addition, the CNP administrative controls

are consistent with the GALL Report. The staff considers this element to be acceptable

because it meets the requirements of Appendix B to 10 CFR Part 50 and the GALL Report.

Operatint Experience The applicant stated that, to date, it has not detected VHP leakage in

either CNP Unit 1 or Unit 2. The applicant stated that, during the Unit 2 Cycle 10 refueling

outage completed in 1994, eddy current testing was performed on 71 of the 78 VHPs. One

penetration showed closely spaced axial indications. The flaw evaluation results showed that

the through-wall acceptance criteria would not be violated for the next 18-month fuel cycle.

During the following Unit 2 Cycle 11 refueling outage completed in 1996,- reinspection of this

penetration identified no significant flaw growth. The applicant stated that it repaired the

penetration by embedding the flaw using an alternate repair method approved by the NRC.

The applicant stated that during refueling outages completed on June 9, 2002, for Unit 1, and

February 28, 2002, for Unit 2, it performed 100-percent bare-metal visual inspections of the

RVHs under the insulation. It also performed either surface examination (eddy current testing

or PT) or ultrasonic testing on the CRDM nozzle penetrations. The applicant did not identify.:

any unacceptable flaws or degradation requiring repair in these inspections. The applicant also

stated that during the Unit 2 refueling outage completed in June 20, 2003, it identified and

repaired small indications on two penetrations and evaluated indications on two other -

penetrations as not needing repair.

RAI B. 1.9.2-7

The Operating Experience element submitted in the application does not include references to

inspections and flaw evaluations in accordance with NRC Bulletins 2002-01, 2002-02, and

2003-02, and NRC Order EA-03-009. Therefore, in RAI B.1.9.2-7, the staff requested that the

3-39
I

applicant update the Operating Experience element to reference the inspections and flaw

evaluations performed that apply to these bulletins and order.

The applicant responded to RAI B.1.9.2-7 in the supplemental letter reply to RAI 1.9.2-1, dated

August 11, 2004. Based on the applicant's response, the staff considers RAI B.1.9.2-7 to be

closed.

UFSAR Supplement

In Appendix A, Section A.2.1.9, to the LRA, the applicant provided the Updated Final Safety

Analysis Report (UFSAR) Supplement for the Control Rod Drive Mechanism and Other Vessel

Head Penetration Inspection Program. The staff reviewed this section and verified that the

information in the UFSAR Supplement adequately summarizes the program activities. The staff

finds this section of the UFSAR Supplement sufficient.

Conclusion

The staff has reviewed the information provided in Section B.1.9 of Appendix B to the LRA as

supplemented by the applicant's responses to the RAls in its letters dated August 11 and 19,

2004. On the basis of this review, the applicant demonstrated that it will have a program in

place, approved by the staff, which demonstrates that the effects of aging associated with

CRDM and other vessel head penetrations will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.0.3.2.4 Diesel Fuel Monitoring

Summary of Technical Information in the Application

Section B.1.10, "Diesel Fuel Monitoring," of the LRA describes the applicant's Diesel Fuel

Monitoring Program. In the LRA, the applicant stated that this existing program is consistent,

with exceptions, with GALL AMP XI.M30, "Fuel Oil Chemistry Program." The applicant further

stated that the Diesel Fuel Monitoring Program ensures that adequate diesel fuel quality is

maintained to prevent corrosion of the fuel oil systems associated with the emergency diesel

generators (EDGs), diesel-driven fire pump, and security diesel.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort.

Furthermore, the staff reviewed the exceptions and its justifications to determine whether the

AMP, with the exceptions, remains adequate to. manage the aging effects for which it is

credited.

In Section B.1.10 of Appendix B to the LRA, the applicant stated that the Diesel Fuel Monitoring Program is consistent with GALL AMP XL.M30 with exceptions. The Diesel Fuel Monitoring Program takes exception to the (1) Scope of Program, Parameters Monitored or Inspected, Detection of Aging Effects, and Corrective Action program elements such that this program does not address, or monitor and sample for microbiologically influenced corrosion (MIC), (2)

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Preventive Actions program element such that no additives are used beyond what the refiner

adds during production, (3) Parameters Monitored/Inspected and Acceptance Criteria program

elements such that (a) only American Society for Testing and Materials-(ASTM) Standard D

1796, "Standard Test Method for Water and Sediment in Fuel Oils by the Centrifuge Method," -

issued 2002, is used for determination of water and sediment, rather than Standards' D 1796

and D 2709 and (b) the applicant specified the method of ASTM Standard D 2276, TStandard

Test Method for Particulate Contaminant in Aviation Fuel by Line Sampling," with a 0.8 pm filter,

instead of the modified ASTM Standard D 2276, Method A, with a 3 pm filter; (4) Detection of '-

Aging Effects element such that the program does not include ultrasonic measurements of tank

bottoms; and (5) Monitoring and trending program element such that the water and particulate

contamination and biological activity are not trended.

The applicant stated in the LRA that plant-specific operating experience has not indicated

significant problems related to MIC. The applicant attributed the lack of such problems to

minimizing water contamination in the diesel fuel storage tanks. The'applicant also stated that

the Diesel Fuel Monitoring Program has effectively managed aging effects. In its 25 years of

operating experience, no evidence of microbial degradation of the fuel or MIC-related corrosion

to fuel system components has been observed. On the basis of its review of operating

experience for the Diesel Fuel Monitoring Program, the staff finds the applicant's exception (i.e.

not to address or monitor and sample for MIC) to be acceptable.

The applicant also stated in the LRA that the diesel fuel contains a comprehensive additive

package provided by the refiner and certified by the supplier that has a higher percentage of a

straight-run distillation component (instead of catalytically cracked), which lends greater

resistance to fuel degradation by oxidation. Further, the storage system, which maintains the

fuel at a nearly constant temperature of 130C (55 OF), enhances the diesel fuel's long-term

stability. Additionally, the applicant stated that, in its 25 years of operating experience, it has

not observed any evidence of microbial degradation of the fuel or MIC-related corrosion' to fuel'

system components. On the basis of its review of operating experience for the Diesel Fuel

Monitoring Program, the staff finds the applicant's exception (i.e., not to use additives beyond

what the refiner adds during production) to be acceptable.

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 CNP. Therefore, the staff finds the applicant's use of Standard D 1796 for the -determination

of water and sediment, rather than Standards D 1796 and D 2709, to be acceptable.'

The guidance in the GALL Report concerning the use of modified ASTM Standard D 2276,'

Method A, allows for use of a filter with a larger (3.0 pm) pore size for the detection of

particulates. The staff noted that the use of a filter with a smaller (0.8 pm) 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 the applicant's use of ASTM Standard D 2276 to

be acceptable.

The applicant stated in the LRA that it visually inspects for degradation the internal surfaces of

tanks that are drained for cleaning. The CNP technical specifications require that EDG fuel oil

storage tanks either be drained and cleaned or that their contents undergo a filtering test every

10 years. The staff reviewed recent fuel oil operating experience, which includes an ultrasonic

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thickness measurement of the tank bottom surface in 1995 and visual tank inspections of both

EDG fuel oil storage tanks in 1996 (i.e., draining, cleaning, and inspecting). In 1995, the

applicant's results for the ultrasonic measurements indicated that the tank plates were within

the manufacturer's tolerance of a new plate. The applicant did not detect any measurable

corrosion or observe any corrosion during the visual tank inspections. In addition, the staff

determined that the applicant mitigated the introduction of fuel oil contaminants into the tanks,

which cause degradation of tank bottoms, through compliance with diesel fuel oil standards and

periodic sampling.

The applicant stated in its engineering report that corrosion may occur at locations in which

contaminants accumulate, such as the tank bottom, and an ultrasonic thickness measurement

of the tank bottom surface ensures that significant degradation is not occurring. The staff

pointed out that this statement in the applicant's program basis document is inconsistent with

the exception taken to perform ultrasonic thickness measurements to check for significant

degradation. The applicant responded that it will not perform ultrasonic thickness

measurements on the tank bottom surface because of the operating experience described

above and the periodic technical specification requirements to drain and clean the tanks or filter

test their contents every 10 years.

On the basis of its review of operating experience, the 10 year drain/clean or filter testing

inspection requirement in the CNP technical specifications, and the controls provided to

minimize introduction of fuel oil contaminants into the tanks, the staff finds that the applicant's

exception to the program ( i.e. to exclude ultrasonic measurements of tank bottoms) to be

acceptable.

The applicant stated that its Corrective Action Program provides reasonable assurance that

trends of repeated failures to meet acceptance criteria will be identified and addressed with

appropriate corrective actions. On the basis of its review of operating experience for the Diesel

Fuel Monitoring Program, the staff finds the applicant exception such that the water and

particulate contamination and biological activity are not trended to be acceptable.

Operating Experience The applicant stated in the LRA that its review of relevant Crs

demonstrates that it has improved this program through evaluation of site and industry

operating experience. As an example, it found the procedure that implements technical

specification surveillance requirements for sampling diesel fuel to be inadequate in providing

explicit instructions for consideration of the dyes that are used to identify the type of the fuel. A

CR documented the procedural deficiency and provided a root cause analysis to resolve the

issues. Corrective actions were implemented to prevent recurrence.

The applicant stated that the Diesel Fuel Monitoring Program has effectively managed aging

effects. In its 25 years of operating experience, the applicant has not observed any evidence of

microbial degradation of the fuel or MIC-related corrosion to the fuel system components.

The staff reviewed records of the ultrasonic measurements of wall thickness performed on

tanks in 1995. The results indicate that the ultrasonic thickness measurements were within

manufacturing tolerances for new material. Because the applicant detected iron oxide sediment

in the tanks, it cleaned these tanks in 1996. Based on the observed condition of the tank walls,

the applicant attributed the sediment to sources outside the tanks. The applicant used the

criteria from ASTM D 4176-82, which specifies "clear and bright appearance" for monitoring

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particulate contamination of the new fuel before its addition to the storage tanks. The staff

noted that the applicant's Corrective Action Program has reported problems with implementing

this procedure which were properly eliminated in accordance with their Corrective Action

Program.

The staff also reviewed the applicant's engineering report that implements the technical

specification requirements. On the basis of corrective actions taken and documentation to the

effect that filters remain free of indications of particulate contamination, the staff finds this 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 the applicant's Diesel Fuel MonitoringProgram adequately manages the aging effects that have been observed at the applicant's

plant.

UFSAR Supplement

In Section A.2.1.1 0 of Appendix A to the LRA, the applicant provided its UFSAR Supplement for

the Diesel Fuel Monitoring Program. The staff reviewed this section and determined that the

information in the UFSAR Supplement adequately summarizes the program activities.- By letter

dated April 23, 2004, the applicant stated that it revised Appendix A, Section A.2.1.10, to clarify

that the program monitors fuel oil quality and contaminant concentrations using ASTM

standards specified in the plant technical specifications. The applicant stated that it made this

revision for completeness. The staff finds this section of the UFSAR Supplement sufficient,

pursuant to 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

attributes of the program for which the applicant claimed consistency with the GALL Report are

indeed consistent with the GALL Report. In addition, the staff has reviewed the exceptions to

the GALL Report and finds that the applicant has demonstrated that it will adequately manage

the effects of aging so that the intended functions of SCs 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

Summary of Technical Information in the Application

Section B.1.1 1.1, -"Fire Protection," of the LRA describes the applicant's Fire Protection

Program. In the LRA, the applicant stated that this existing CNP program will be consistent,

with exceptions and enhancements, with GALL AMP XI.M26, "Fire Protection."

The applicant stated in the LRA that the Fire Protection Program includes a fire barrier

inspection and a diesel-driven fire pump inspection. The fire barrier inspection requires (1) .

periodic visual inspection of fire barrier penetration seals and fire barrier walls, ceilings, and I

floors, and (2) periodic visual inspection and functional tests of fire-rated doors to ensure that

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their operability is maintained. The diesel-driven fire pump inspection requires that the pump be

periodically tested to ensure that the fuel supply line can perform the intended function. The

program includes periodic inspection and testing of the halon/carbon dioxide (CO2) fire

suppression system.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort.

Furthermore, the staff reviewed the exceptions and enhancements and their justifications to

determine whether the AMP, with the exceptions and enhancements, remains adequate to

manage the aging effects for which it is credited.

In Section B.1.1 1.1 of Appendix B to the LRA, the applicant stated that the Fire Protection

Program will be consistent with GALL AMP XL.M34 with exceptions and enhancements. The

Fire Protection Program takes exception to the Parameters Monitored or Inspected and

Detection of Aging Effects program elements in that (1) fire doors clearances are inspected

when fire doors are physically removed for maintenance or repair or for new installations, not

bimonthly as recommended by the GALL Report, (2) function tests of fire doors are performed

every 6 months (to verify the operability of automatic hold-open, closing mechanisms, and

latches), not daily, weekly, or monthly as recommended by the GALL Report, and (3) visual

inspection and functional tests of the halon/CO2 fire suppression system are performed every

18 months, not every 6 months as recommended by the GALL Report. Consistent with Interim

Staff Guidance (ISG)-4, "Fire Protection System Piping," inspections for charging pressure,

valve lineups, and automatic mode of operation are not credited for aging management.

In ISG-4, the NRC revised the criteria for the GALL AMP XL.M26 Parameters Monitored or

Inspected and the Detection of Aging Effects program elements to no longer require visual

inspection or functional testing of fire doors on a specific frequency. Rather, the applicant can

establish a plant-specific interval to verify 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-4. Therefore, the staff finds

this exception to be acceptable.

The Fire Protection Program also takes exception to the Monitoring and Trending program

element in that trending for this program is performed via the applicant's Corrective Action

Program. The applicant stated that the use of its Corrective Action Program provides

reasonable assurance that it will identify trends entailing repeat failures to meet acceptance

criteria and address them with appropriate corrective actions. On this basis, the staff finds this

exception acceptable.

In addition, the applicant committed in the LRA that it will enhance the Fire Protection Program

to ensure that the CO2 and halon procedures require that conditions that may affect the

performance of the system (i.e.., corrosion, mechanical damage, or damage to dampers) are

observed and degraded conditions are addressed. The applicant will also enhance that

procedure to ensure that the diesel fuel supply line is monitored for degradation during

performance testing. This is Commitment #7 in Appendix A of this SER. These enhancement

will be made to the Parameters Monitored or Inspected, Detection of Aging Effects, Monitoring

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and Trending, and Acceptance Criteria program elements. The applicant stated in the LRA that

it will implement these enhancements before the period of extended operation.

The applicant stated that these enhancements will ensure that material conditions that may

affect performance of the halonlCO2 fire suppression system, such as corrosion, mechanical

damage, or damage to dampers, are monitored and are subject to the Corrective Action

Program.

On the basis that the applicant will revise and clarify the requirements in its plant procedures to

further ensure that aging effects are detected and addressed, the staff finds these

enhancements to be acceptable.

Operating Experience The applicant stated in the LRA that its CR review found that minor

problems with fire protection equipment have been identified and resolved. It performed.

self-assessments of the program in 1995 and 2002. These assessments identified no

significant aging of fire protection components. This operating experience demonstrates that -

the Fire Protection Program effectively manages the effects of aging on fire protection

equipment. The applicant also stated that this conclusion is corroborated by the findings of a

1998 NRC inspection that fire protection equipment was well maintained.

The applicant further stated that, as a result of its review of the CRs, self-assessments, and

NRC inspections, it concluded that implementation of the existing Fire Protection Program

maintains fire protection equipment and meets applicable regulatory requirements. Thus, this

program manages aging effects on fire protection equipment.

The staff reviewed operating experience for the Fire Protection Program. Trending data did notidentify deficiencies to this program. A review'of the applicant's self-assessment performed in

2002 confirmed that the review did not identify any significant aging of fire protection

components. The NRC conducted a triennial fire protection inspection and documented it in a

July 16, 2003, inspection report to the applicant. Based on a review of the latest

documentation, the staff concludes that the applicant has identified operating experience for the

Fire Protection Program and performed corrective actions, where needed, as a result. '

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the Fire Protection Program adequately

manages the aging effects that'have been observed 'at the applicant's plant. .

UFSAR Supplement

In Appendix A, Section A.2.1.13, to 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 Supple'nent adequately summarizes 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.

attributes of the program forlwhich the applicant claimed consistency with the GALL Report are,.

indeed,' consistent with the GALL Report. In addition, the staff has reviewed the exceptions and

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enhancements to the GALL Report program and finds that the applicant has demonstrated that

it will effectively manage the effects of aging so that the intended functions of SCs 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).

3.0.3.2.6 Fire Water System

Summary of Technical Information in the Application

Section B.1.11.2, "Fire Water System," of the LRA describes the applicant's Fire Water System

Program. In the LRA, the applicant stated that this existing CNP program will be consistent,

with exceptions and enhancements, with GALL AMP XL.M27, "Fire Water System."

The applicant stated that its Fire Water System Program applies to water-based fire protection

systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes,

and aboveground and underground piping and components that are tested in accordance with

the applicable National Fire Protection Association (NFPA) codes and standards. Such testing

assures the minimum functionality of the systems. In addition, these systems are normally

maintained at the required operating pressure and monitored in that leakage resulting in the

loss of system pressure is immediately detected and corrective actions initiated.

The applicant also stated that it will inspect a sample of sprinkler heads using the guidance in

Section 2.3.3.1 of NFPA 25, "Inspection, Testing and Maintenance of Water-Based Fire

Protection Systems." In part, NFPA 25 states that, "where sprinklers have been in place for 50

years, they shall be replaced or representative samples from one or more sample areas shall

be submitted to a recognized testing laboratory for field service testing." NFPA 25 also

contains guidance to perform this sampling every 10 years after the initial field service testing.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort.

Furthermore, the staff reviewed the exceptions and enhancements and their justifications to

determine whether the AMP, with the exceptions and enhancements, remains adequate to

manage the aging effects for which it is credited.

In Section B.1.11.2 of Appendix B to the LRA, the applicant stated that the Fire Water System

Program will be consistent with GALL AMP XI.M27 with exceptions and enhancements. The

Fire Water System Program takes exception to the Parameters Monitored or Inspected

program element in that the applicant does not implement the commitments in NRC GL 89-13,

"Service Water System Problems Affecting Safety-Related Equipment," dated July 18, 1989, for

the Fire Water System Program, as recommended in the GALL Report.

The applicant stated in the LRA that it verifies that every fire main segment (excluding individual

system supplies) is clear of obstruction by performing a full-flow test at least once every 3

years. The NRC's ISG-4 revises the criteria for the GALL AMP XL.M27 Parameters Monitored

or Inspected program element so that it no longer recommends the use of GL 89-13 in

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determining the system's ability to maintain pressure and internal system corrosion conditions.

Rather, ISG-4 recommends either periodic flow testing of the fire water system using the

guidelines of 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 is in accordance

with ISG-4 and is, therefore, acceptable. This is Commitment #8 in Appendix A of this SER.

The Fire Water System Program also takes exception to the Detection of Aging Effects

program element in that (1) the fire hydrant hose gasket inspections are performed once every:

18 months rather than annually as recommended by the GALL Report, and (2) fire hydrant hose

hydrostatic tests and fire hydrant flow tests are performed at least once every 3 years rather

than annually as recommended by the GALL Report.

The staff finds that the applicant's proposed inspection frequencies,following NFPA guidance,

are sufficient to detect aging effects which act over a considerable period of time. On the basis

of the applicant's commitment to test fire water system components in accordance with the

applicable NFPA 25 guidelines, the staff finds these exceptions to be acceptable. ;

Lastly, the Fire Water System Program takes exception to the Monitoring and Trending

program element in that trending for this program is performed via the applicant's Corrective

Action Program. For the program element associated with the exception taken by the applicant,

the GALL Report states that results of system performance testing are monitored and trended

as specified by the NFPA codes and standards. Degradation identified by internal inspection is

evaluated. In the LRA, the applicant stated that use of the Corrective Action Program for

Monitoring and Trending system performance provides reasonable assurance that it will identify

trends entailing repeat failures to meet acceptance criteria and address them with appropriate

corrective actions. The staff reviewed the operating experience associated with the Fire Water

System Program. On the basis of this operating experience review and 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 is acceptable.

The applicant stated in the LRA that it will enhance the Fire Water System Program Scope of

Program and Detection of Aging Effects program elements in that a'sample of sprinkler heads

will be inspected using the guidance of NFPA 25, Section 2.3.3.1. In addition, NFPA 25

contains guidance to repeat this sampling every 10 years after the initial field service testing.

The NRC's ISG-4 revises the criteria for the GALL AMP XI.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 Report criteria in ISG-4 and the applicant's commitment to rely upon

applicable codes and standards to develop test procedures,'the staff finds this enhancement to

be acceptable. - ; - --

The applicant also stated that it will enhance the Scope of Program, Detection of Aging Effects,

and Monitoring and Trending program elements for the Fire Water System Program to

implement the requirements of ISG-4 pertaining to nonintrusive measurement of pipe wall

thickness.

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The NRC's ISG-4 revises the criteria for the GALL AMP XL.M27 Scope of Program, Detection of

Aging Effects, and Monitoring and Trending program elements to recommend nonintrusive (i.e.,

volumetric test) examinations of fire system piping to detect signs of internal corrosion as an

alternative to disassembly of pipe segments for inspection. According to ISG-4, applicants

should perform baseline nonintrusive pipe wall thickness evaluations of the fire protection piping

to detect this aging effect before the current license term expires. The staff further

recommends, in ISG-4, that applicants perform pipe wall thickness evaluations at plant-specific

intervals, determined by postinspection engineering evaluations, during the period of extended

operation. On the basis of the revised GALL Report criteria in ISG-4 and the applicant's

commitment to rely upon applicable codes and standards to develop test procedures, the staff

finds this enhancement to be acceptable.

Operating Experience The applicant stated, in the LRA, that it included the operating

experience for the Fire Water System Program with that for the Fire Protection Program

because the CNP procedures, self-assessments, and NRC inspections cover both programs as

one. The applicant's condition report review found that minor problems with fire protection

equipment have been identified and resolved. The applicant performed self-assessments of

the program in 1995 and 2002, which did not identify any significant aging of fire protection

components. This operating experience demonstrates that the Fire Protection Program

effectively manages the effects of aging on fire protection equipment. The applicant also stated

that the findings of a 1998 NRC inspection that fire protection equipment was well maintained

corroborate this conclusion.

The applicant further stated that, as a result of its review of the CRs, self-assessments, and

NRC inspections, it concluded that implementation of the existing Fire Protection Program

maintains fire protection equipment and meets applicable regulatory requirements. Thus, this

program manages aging effects on fire protection equipment.

The staff reviewed operating experience for the Fire Water System Program. A review of the

results of a self-assessment that the applicant performed in 2002 confirmed that it did not

identify any significant aging of fire protection components. The NRC held its triennial fire

protection inspection and documented it in a July 16, 2003, inspection report. Based on a

review of the latest documentation, the staff concludes that operating experience for the Fire

Water System Program has been captured and program enhancements have been performed

as a result.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the Fire Water System Program adequately

manages the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.14 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Fire Water System Program. The staff reviewed this section and determined that the

information in the UFSAR Supplement adequately summarizes the program activities. The staff

finds this section of the UFSAR Supplement sufficient.

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Conclusion

On the basis of its review and audit of the applicant's program, the'staff finds that those - -

attributes of the program for which the applicant claimed consistency with the GALL Report are'

indeed consistent with the GALL Report. In addition, the staff has reviewed the exceptions and

enhancements to the GALL Report and finds that the'applicant has demonstrated that it will

adequately manage the effects of aging so that the intended functions of SCs 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).

3.0.3.2.7 Inservice Inspection-ASME Section Xl, Inservice Inspection, Subsection IWE

Summary of Technical Information in the Application

Section B.1.15, "Inservice Inspection-ASME Section XI, Inservice Inspection, Subsection

IWE," of the LRA describes the applicant's Inservice Inspection-ASME Section XI, Inservice

Inspection, Subsection IWE Program.- In the LRA, the applicant stated that this'existing CNP

program will be consistent, with exceptions, with GALL AMP XI.S1 ,"ASME Section Xl,

Subsection IWE."

The applicant stated in the LRA that 10 CFR 50.55a specifies the use of the examination

requirements in the ASME Code, Section Xl, Subsection IWE, for steel liners of concrete

containments and other containment components. The applicant has the implemented ASME

Code, Section XI, 1992 Edition with the 1992 Addenda, as approved in 10 CFR 50.55a.

Subsection IWE and the additional requirements specified in 10 CFR 50.55a(b)(2) constitute an

existing required program that is applicable to managing aging for license renewal.

The applicant stated in the LRA that the Subsection IWE program encompasses (1) concrete

containment steel liners and their integral attachments, (2) containment hatches and airlocks,

(3) seals, gaskets, and moisture barriers, and (4) pressure-retaining bolting. Subsection IWE

specifies visual examination (i.e., general visual, VT-3, or VT-1) as the primary ISI method.

Limited volumetric examination (ultrasonic thickness measurement) and surface'examination

(i.e., liquid penetrant) may also be necessary in some instances. Subsection IWE specifies

acceptance criteria, corrective actions, and expansion of the inspection scope when

degradation exceeding the acceptance criteria is found.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's-claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort.

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 Section B.1.15 of Appendix B to the LRA, the applicant stated that the Inservice

Inspection-ASME Section XI, Subsection IWE Program will be consistent with GALL AMP

XI.S1 with exceptions. The Inservice Inspection-ASME Section XI, Subsection IWE Program

3-49
I

takes exception to the Scope of Program and Parameters Monitored or Inspected program

elements in that it does not (1) examine Category E-D seals and gaskets and (2) include the

Category E-G bolt torque or tension test. For the program elements associated with the

exceptions taken by the applicant, the GALL Report states that the components within the

scope of Subsection IWE are Class MC pressure-retaining components and their integral

attachments, metallic shell and penetration liners of Class CC containments and their integral

attachments, containment seals and gaskets, containment pressure-retaining bolting, and metal

containment surface areas. In addition, Table IWE-2500-1 specifies that Category E-D seals

and gaskets will undergo visual examination (VT-3); Category E-G pressure-retaining bolts will

undergo visual examination (VT-1) as well as bolt torque or tension tests.

In the LRA, the applicant cited approved relief requests that allow for verifying the

pressure-retaining capability of seals and gaskets by 10 CFR Part 50, Appendix J, Type B

leakage testing. The applicant stated that it performs Appendix J Type B leakage testing at

least once each inspection interval. The applicant's approved relief requests also include the

following alternate provisions to ensure the structural integrity and the leak-tightness of Class

MC pressure-retaining bolting:

* Exposed surfaces of bolted connections will be visually examined in accordance with

requirements of Table IWE-2500-1, Examination Category E-G, Pressure Retaining

Bolting, Item E8.10.

* Bolted connections will meet the pressure test requirements of Table IWE-2500-1

Examination Category E-P, All Pressure Retaining Components, Item E9.40.

The staff reviewed the relief requests and finds that they provide alternative methods for

ensuring that the pressure boundary and structural integrity functions are maintained. Thus, it

is not necessary to perform additional tests in accordance with the GALL Report

recommendations. On this basis, the staff finds these exceptions to be acceptable.

The Inservice Inspection-ASME Section Xl, Subsection IWE Program also takes exception to

the Monitoring and Trending program element, in that successive examinations required by

IWE-2420(b) and IWE-2430(c) are limited to Class MC components accepted by evaluation in

accordance with IWE-3122.4, excluding successive examination of repaired components. For

the program element associated with the exception taken by the applicant, the GALL Report

states that when component examination results require evaluation of flaws, areas of

degradation, or repairs, and the component is found to be acceptable for continued service, the

areas containing such flaws, degradation, or repairs must be reexamined during the next

inspection period, in accordance with Examination Category E-C. When these reexaminations

reveal that the flaws, areas of degradation, or repairs remain essentially unchanged for three

consecutive inspection periods, these areas no longer require augmented examination in

accordance with Examination Category E-C.

In its LRA, the applicant cited an approved relief request that limits the successive examinations

required by IWE-2420(b) and IWE-2430(c)) to Class MC components accepted by evaluation in

accordance with IWE-3122.4. This limitation excludes successive examination of repaired

components. The staff reviewed the relief request and, on that basis, finds this exception to be

acceptable.

3-50
Operatina Experience The applicant stated in the LRA that it performed a self-assessment of

Subsection IWE and IWL programs in the fall of 1999, when these programs and their

respective implementing documents were under development. The review concluded that the

Subsection IWE and IWL programs would be effective structural monitoring programs.

The applicant also stated that operating experience, as documented in CRs and licensee event

reports (LERs), indicates that the program effectively monitors containment liner conditions and

prescribes appropriate actions when problems are found. For example, the applicant found a

hole in the Unit 2 containment liner during the IWE general visual examination. This hole,

which went undetected until the first IWE examination, resulted from an inadequate repair of a

hole erroneously drilled through the liner during original construction. As another example, the

applicant identified liner corrosion when it removed the concrete floor-to-liner joint seal. This

area of the liner plate is normally inaccessible and exempt from IWE examination requirements.

However, the applicant revised the IWE program to add examinations of this area.

The staff reviewed the operating experience associated with the Inservice Inspection-ASME

Section Xl, Inservice Inspection, Subsection IWE Program, including the applicant's 1999

self-assessment. Several CRs and two LERs were generated as a result of the selfassessment and other inspections. The applicant revised the IWE program as a result of the

identified conditions and corrective actions.; The staff confirmed this revision and, on this basis,-

finds this program to be acceptable.

Based on its review of the above operating experience and discussions with the applicant's

technical staff, the staff concludes that the Inservice Inspection-ASME Section Xl, Inservice

Inspection, Subsection IWE Program adequately manages the aging effects that have been

observed at the applicant's plant.

UFSAR Supplement -

In Section A.2.1.18 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Inservice Inspection-ASME Section Xl, Inservice Inspection, Subsection IWE Program.:.

The staff reviewed this section and determined that the information in the UFSAR Supplementadequately summarizes 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

attributes of the program for which the applicant claimed consistency with the GALL Report are

indeed consistent with the GALL -Report. In addition, the staff has reviewed the exceptions to

the GALL Report and finds that the applicant has demonstrated that it will adequately manage

the effects of aging so that the intended functions of SCs 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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3.0.3.2.8 Inservice Inspection-ASME Section Xl, Subsection IWL

Summary of Technical Information in the ApDlication

Section B.1.17, "Inservice Inspection-ASME Section Xl, Subsection IWL," of the LRA

describes the applicant's Inservice Inspection-ASME Section Xl, Subsection IWL Program. In

the LRA, the applicant stated that this existing CNP program will be consistent, with exceptions,

with GALL AMP XI.S2, "ASME Section Xl, Subsection IWL."

Title 10, Section 50.55a, of the Code of Federal Regulations (10 CFR 50.55a) specifies the use

of the examination requirements in the ASME Code, Section Xl, Subsection IWL, for reinforced

concrete containments (Class CC). The applicant has implemented the ASME Code, Section

Xl, 1992 Edition with the 1992 Addenda, as approved in 10 CFR 50.55a. Subsection IWL and

the additional requirements specified in 10 CFR 50.55a(b)(2) constitute an existing required

program that is applicable to managing aging for license renewal.

Staff Evaluation

During its audit and review, the staff confirmed the'applicant's claim of consistency with the.

GALL Report. The audit and review report document staff's evaluation of this effort.

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 Section B.1.17 of Appendix B to the LRA, the applicant stated that the Inservice

Inspection-ASME Section Xl, Subsection IWL Program will be consistent with GALL AMP

XI.S2 with exceptions. The Inservice Inspection-ASME Section Xl, Subsection IWL Program

takes exception to the Scope of Program, Parameters Monitored or Inspected, Monitoring and

Trending, and Acceptance Criteria program elements, in that posttensioning systems would not

be within the scope of this program. The applicant stated in the LRA that it does not have a

posttensioning system. The staff agrees with the applicant, and on this basis the staff finds this

exception to be acceptable.

The Inservice Inspection-ASME Section Xl, Subsection IWL Program also takes exception to

the Detection of Aging Effects program element, in that the maximum direct examination

distance specified for remote visual examinations may be extended and the minimum

illumination requirements specified may be decreased, provided the conditions or indications for

which the visual examination is performed can be detected at the chosen distance and

illumination. For the program element associated with the exception taken by the applicant, the

GALL Report states that the frequency and scope of examinations specified in 10 CFR 50.55a

and Subsection IWL ensure that aging effects would be detected before they would

compromise the design-basis requirements. The frequency of inspection is specified in

IWL-2400. Concrete inspections are performed in accordance with Examination Category L-A.

Subsection IWL requires the performance of ISIs for concrete and unbonded posttensioning

systems at 1, 3, and 5 years following the structural integrity test. Regarding detection methods

for aging effects, all concrete surfaces receive a visual VT-3C examination. Selected areas,

such as those that indicate suspect conditions and areas surrounding tendon anchorages,

receive a more rigorous VT-I or VT-1 C examination. These visual examination methods and

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testing would identify the aging effects of accessible concrete components and prestressing

systems in concrete containments.

The applicant stated in the LRA that an approved relief request includes alternate provisions

related to the remote performance of the visual examinations required in accordance with

IWL-2510. Specifically, the maximum direct examination distance specified in Table

IWA-221 0-1 may be extended and the minimum illumination requirements specified in Table'

IWA-221 0-1 may be decreased, provided that the conditions or indications for which the

examination is performed can be detected at the chosen distance and illumination. On the:'

basis of the approved relief request, the staff finds this exception to be acceptable.

Operating Experience The applicant stated in the'LRA that it performed a self-assessment of

the Subsection IWE and IWL programs in the fall of 1999, when the programs and their - -

respective implementing documents were under development. The review concluded thatithe

Subsection IWE and IWL programs would be effective structural monitoring programs.,

The applicant also stated that operating experience for the Subsection IWL program, although

limited, indicates that this program effectively monitors containment concrete condition and - -

prescribes appropriate actions when problems are found. Program inspections have identified

only minor problems.- A Subsection IWL ISI conducted in 2001 revealed several surface -

discrepant conditions in the form of buried wood, exposed rebar, and plastic. Based on the

evaluation of the conditions, the applicant concluded that the containment structural integrity -

was unaffected. The applicant further stated that the program will continue to trend these areas

at inspection interval frequencies sufficient to discover degradation well in advance of any

impact on the structural integrity of the containment structure.

The staff reviewed the operating experience for the Inservice Inspection-ASME Section Xl,

Subsection IWL Program, including the results of the inspection conducted in 2001. The staff

agrees with the applicant that the presence of foreign material or exposed reinforcing bar'does''

not affect the containment structural integrity.

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 Inservice Inspection-ASME Section Xl,

Subsection IWL:Program adequately manages the aging effects that have been observed at

the applicant's plant.

UFSAR Supplement,-.,

In Section A.2.1.20 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Inservice Inspection-ASME Section Xl, Subsection IWL Program. The staff reviewed

this section and determined that the information in the UFSAR Supplement adequately

summarizes 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

attributes of the program for which the applicant claimed consistency with the GALL Report are,

indeed, consistent with the GALL Report. In addition, the staff has reviewed the exceptions to

3-53.
the GALL Report and finds that the applicant has demonstrated that it will adequately manage

the effects of aging so that the intended functions of SCs 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).

3.0.3.2.9 Non-EQ Instrumentation Circuits Test Review

Summary of Technical Information in the Application

Section 3.1.21, "Non-EQ Instrumentation Circuits Test Review," of the LRA describes the

applicant's Non-EQ Instrumentation Circuits Test Review Program. In the LRA, the applicant

stated that this new program will be consistent with, but include an exception to, GALL AMP

XL.E2, "Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits."

The applicant stated in the LRA that this program provides reasonable assurance that the

intended functions of specified electrical cables not subject to environmental qualification (EQ)

will be maintained consistent with the CLB through the period of extended operation. The

electrical cables included in the scope of this program (1) are not subject to the EQ

requirements of 10 CFR 50.49, (2) are used in instrumentation circuits with sensitive,

high-voltage, low-level signals, and (3) are exposed to adverse localized environments caused

by heat, radiation, or moisture. An adverse localized environment is one that is significantly

more severe than the specified service environment for the cable.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort.

Furthermore, the staff reviewed the exception and its justifications to determine whether the

AMP, with the exception, remains adequate to manage the aging effects for which it is credited.

In Section B.1.21 of Appendix B to the LRA, the applicant stated that the Non-EQ

Instrumentation Circuits Test Review Program will be consistent with GALL AMP XL.E2, with an

exception. The Non-EQ Instrumentation Circuits Test Review Program takes exception to the

Detection of Aging Effects program element in that it will perform the first reviews before the

period of extended operation and every 10 years thereafter, rather than perform the reviews at

the normal calibration frequency specified in the technical specifications. The applicant will

review calibrations or surveillances that fail to meet the acceptance criteria at the time of the

calibration or surveillance. For the program element associated with the exception taken by the

applicant, the GALL Report states that the normal calibration frequency specified in the plant

technical specifications provides reasonable assurance that severe aging degradation will be

detected before the loss of the cable intended function. The first tests for license renewal must

be completed before the period of extended operation. In addition, calibration provides

sufficient indication of the need for corrective actions by monitoring key parameters and

providing trending data based on acceptance criteria related to instrumentation loop

performance.

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In discussions with the staff during the audit, the applicant further clarified its position regarding

inspection frequency by stating that it intends to closely match the guidance that will be

provided in ISG-15, 'Revision to Generic Aging Lessons Learned Aging Management Program

(AMP) XI.E2," when the guidance is released for final use.

By letter dated May 6, 2004, the staff forwarded an RAI to the applicant that requested

confirmation that the applicant intends to be consistent with the proposed ISG-1 5 in its

management of non-EQ cables sensitive to a reduction in insulation resistance. This SER

addresses this issue in the staff evaluation of the applicant response to RAI 3.6-2 in Section

3.6.2.1 under the "Staff RAls Pertaining to Recent Operating Experience and Emerging Issues"

subsection. -

Operating Experience The applicant stated in the LRA that it will initiate the program before the

period of extended operation; therefore, there is no operating experience. As appropriate, the

applicant will corisider industry and plant-specific operating experience in the development of

this program.

The staff finds this acceptable in that the normal inspection process provides reasonable

assurance that the applicant will review operating -experience in the future to provide'objective

evidence to support the conclusion that the effects of aging will be managed adequately.

On the basis of its review and discussions with the applicant's technical staff, the staff

concludes that the Non-EQ Instrumentation Circuits Test Review Program adequately manages

the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.24 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Non-EQ Instrumentation Circuits Test Review Program. The staff reviewed this section

and determined that the information in the UFSAR Supplement adequately summarizes 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

attributes of the program for which the applicant claimed consistency with the GALL Report are,'

indeed -consistent with the GALL Report. In addition, the staff has reviewed the exception to

the GALL Report and finds that the applicant has demonstrated that it will adequately manage

the effects of aging so that the intended functions of SCs 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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3.0.3.2.10 Reactor Vessel Integrity

Summary of Technical Information in the Application

Section B.1.26, "Reactor Vessel Integrity," of the LRA discusses the applicant's Reactor Vessel

Surveillance Program. The applicant stated that the program is consistent with GALL AMP

XI.M31, "Reactor Vessel Surveillance."

Staff Evaluation

In LRA Section B.1.26, the applicant described its AMP to manage aging in reactor vessel

beltline materials. The LRA stated that this AMP will be consistent with GALL AMP XI.M31,

"Reactor Vessel Surveillance," with the inclusion of two improvements:

(1) the testing of one additional capsule for each unit between 32 effective full-power years (EFPYs) and 48 EFPYs to address the peak fluence expected at 60 years

(2) the adjustment of surveillance data and assessment of impact on embrittlement to

address changes in neutron energy spectrum or operating temperature

For this AMP, the GALL Report recommends further evaluation regarding the proposed surveillance capsule withdrawal schedule. The staff reviewed LRA Section B.1.26 to determine

whether the applicant properly applied the GALL program to its facility. The staff also reviewed

the applicant's evaluation to determine whether the AMP addressed the issue regarding an

acceptable reactor vessel surveillance program.

RAI B. 1.26-1

Section B.1.26 of the LRA indicates that the applicant will withdraw and test a capsule from

each unit, Capsule W for Unit 1 and Capsule S for Unit 2, at approximately 32 EFPYs.

Between 32 and 48 EFPYs, it will withdraw and test an additional capsule from each unit with a

neutron fluence approximately equivalent to the peak reactor vessel fluence at 48 EFPYs.

According to the current capsule withdrawal schedule, documented in WCAP-12483,

Revision 1, "Analysis of Capsule U from the American Electric Power Company D.C. Cook

Unit 1 Reactor Vessel Radiation Surveillance Program," Capsule W for Unit 1 has already reached a neutron fluence equivalent to 32 EFPYs and Capsule S for Unit 2 will reach a

neutron fluence of 1.983x1 019 neutron per square centimeter (n/cm2) (E 2 1 million electron

volts (MeV)) at the time of withdrawal. Considering that Capsule W for Unit 1 was formerly located at the 4-degree position and known as Capsule S, and Capsule S for Unit 1 was

formerly known as Capsule W, in RAI B.1.26-1, the staff requested that the applicant confirm

that the LRA reported the most recent information regarding capsule identification. The staff

also asked the applicant to provide the projected fluence in n/cm2 and in EFPYs relative to the

fluence at the peak RPV fluence location for Capsule W for Unit 1 and Capsule S for Unit 2 at

the proposed time of their withdrawal (between 32 and 48 EFPYs).

The applicant responded in its letter dated August 19, 2004, that the Unit 1 capsule identification was wrong and provided the following replacement for the LRA Section 8.1.26

table entry regarding the proposed improvement for Monitoring and Trending program element:

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I&M will pull and test one additional standby capsule for each unit between 32 EFPY and

48 EFPY to address the peak fluence expected at 60 years. A fluence update will be

performed at approximately 32 EFPY when Capsule S in each unit is pulled and tested.

A subsequent fluence update will be performed when the standby capsules are pulled

and tested between 32 EFPY and 48 EFPY.

The applicant further reported that the projected fluence and removal time for Unit 1 Capsule S

are estimated as 2.018x10 9 n/cm2 and 32 EFPY, and for Unit 2 Capsule S,1.983x10'9 n/cm2

and 32 EFPY.. The applicant has corrected a mistake in the Unit 1 capsule identification and

has provided the fluence information requested by the staff regarding the capsules to be

withdrawn at 32 EFPY. The staff considers the response satisfactory and RAI B.1.26-1 is

resolved. The proposed improvement cited above and another enhancement regarding actions:

to be taken due to modifications to design and operation are specified in Commitment #17 in

Appendix A of this SER.

Appendix H to 10 CFR Part 50 specifies surveillance program criteria for 40 years of operation.

GALL AMP XI.M31 specifies additional criteria for 60 years of operation. The staff determined

that compliance with Appendix H criteria regarding capsule design, location, specimens, test

procedures, and reporting remain appropriate for the applicant's Reactor Vessel Integrity

Program because these items, which satisfy Appendix H now, will stay the same throughout the

extended period of operation. To ensure that all capsules in the reactor vessel that will be

removed and tested during the period of extended operation still meet the test procedures and

reporting requirements of ASTM E 185-82, the staff imposed conditions, as stated at the end of

this discussion, to address this specific concern. The discussion below, regarding GALL's.-.-

consideration of eight items for an acceptable Reactor-Vessel Surveillance Program (RVSP) for

60 years of operation, addresses the Appendix H capsule withdrawal schedule during the -

extended period of operation.

Items 1 to 3 and Item 8 relate to the monitoring of the RPV embrittlement.for upper-shelf energy

(USE) and pressure temperature (P-T) limits for 60 years in accordance with Regulatory.Guide

(RG) 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials." The staff

determined that the CNP LRA has satisfied these considerations based on the evaluations and

conclusions of SER Section 4.2.1 on Charpy USE and SER Section 4.2.3 on PjT limits.

Item 4 relates to the disposition of pulled and tested capsules for possible future reconstitution

use. Item 6 suggests that all other standby capsules exceeding the equivalent RPV fluence of

60 years be removed and placed in storage. LRA Section B.1.26 did not provide this.:

information. The staff requested clarification in RAI B.1.26-2.

RAI B. 1.26-2

In response to RAI B.1.26-2, in a letter dated October 18, 2004 the applicant stated the

following:

.. [c]onsistent with NUREG-1801, Section XI.M31, Item 4, I&M will place all capsules:

that are pulled and tested after August 31, 2000, in storage. -

Because the lead factors for the remaining standby capsules are slightly above 1.0, 1&M

plans to keep the remaining standby capsules in the vessel should l&M decide to pursue

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a second license renewal term (i.e.., operation to 80 years). As required by 10 CFR 50,

Appendix H, I&M will comply with American Society for Testing Materials (ASTM) E

185-82, Table 1, which requires that the standby capsules fluence not be less than once

or greater than twice the peak end-of-life vessel fluence.

The staff accepts this response even though it appears that the applicant's decision to keep the

remaining standby capsules in the vessel to maintain the standby capsules fluence at a level

not less than once or greater than twice the peak end-of-life vessel fluence is not consistent

with the GALL example regarding Item 6, which suggests that all other standby capsules

exceeding the equivalent RPV fluence of 60 years be removed and placed in storage. The

staff's determination is based on the observations that (1) the GALL example does not interpret

the Item 6 philosophy properly, which seeks to avoid a situation where further exposure would

not provide meaningful metallurgical data and (2) the applicant's approach is in accordance with

ASTM E 185-82. Although ASTM E 185-82 applies only to the current period of operation, this

specific requirement regarding the standby capsules fluence limit remains valid technically for

the extended period of operation. Based on the above, the staff has determined that RAI

B.1.26-2 is closed.

Items 5 through 7 in GALL AMP XI.M31 provide recommendations for the withdrawal of

capsules during the period of license renewal. The staff has determined that, with the inclusion

of the first improvement, the applicant's AMP meets Item 5 in GALL AMP XI.M31, which

recommends that at least one capsule should remain in the RPV for testing during the period of

extended operation. The withdrawal schedule for this capsule shall be provided for NRC review

as specified in the NRC license condition for approving this AMP. With the inclusion of the

second improvement, this AMP meets Item 6 in GALL AMP XI.M31 regarding possible future

changes to the RPV exposure conditions (e.g. neutron flux, spectrum, irradiation temperature).

However, the staff noticed that Item 6 also requires that all other standby capsules exceeding

the equivalent RPV fluence of 60 years be removed and placed in storage. Consequently, the

staff needs the projected dates for all standby capsules (Capsule V and Z for Unit 1 and

Capsules V, W, and Z for Unit 2) to reach the fluence equivalent to 60 years of RPV fluence, as

well as the plan to remove and store these standby capsules. This concern is addressed in RAI

B.1.26-2. Item 7 does not apply to this AMP because this item relates only to applicants without

in-vessel capsules. The applicant has multiple standby capsules for both units, and some

standby capsules will be in the RPV throughout the period of extended operation for fluence

information valuable to the CNP RPVs beyond the period of extended operation.

UFSAR Supplement

The staff also reviewed the applicant's UFSAR Supplement for this AMP. This UFSAR

Supplement provides a general description of the Reactor Vessel Surveillance Programs for

CNP, Units 1 and 2. Appendix H to 10 CFR Part 50 requires licensees to submit any proposed

changes to their Reactor Vessel Surveillance Program withdrawal schedules to the NRC for

review and approval. To ensure that this reporting requirement will carry forward after renewal

of the the CNP operating licenses, the staff will impose the following license condition in the

renewed licenses for CNP, Units 1 and 2, that requires the applicant to submit future changes

to the RVSP withdrawal schedules 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

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the configuration of the specimens in the capsule. Any changes to the capsule

withdrawal schedule, includirg spare capsules, must be approved by the NRC prior to

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

With this license condition, the summary description of the program, as required by

10 CFR 54.21 (d), is adequate. Therefore, the staff concludes that the applicant has identified

actions that it has taken or will take to manage the effects of aging during the period of -

extended operation on the functionality of SCs subject to this AMR, such that there is

reasonable assurance that the activities authorized by a renewed license will continue to be

conducted in accordance with the CLB, as required by 10 CFR 54.29(a).

Conclusion

On the basis of its review and audit of the applicant's AMP, the staff finds that it is consistent

with the GALL Program. In addition, the staff has reviewed the improvements to the plant's

existing surveillance program and finds that the applicant has demonstrated that it will

adequately manage the effects of aging so that the intended functions of SCs will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.0.3.2.11 Service Water System Reliability -

Summary of Technical Information in the Application

Section B.1.29, "Service Water System Reliability," of the LRA describes the applicant's Service

Water Reliability Program. In the LRA, the applicant stated that this existing CNP program will

be consistent, with exceptions and enhancements, with GALL AMP XL.M20, "Open-Cycle

Cooling Water System."

The applicant stated in the LRA that the Service Water System Reliability Program relies on

implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the

essential service water (ESW) system will be managed for the period of extended operation.

The program includes surveillance and control techniques to manage aging effects caused by

biofouling, corrosion, erosion, protective coating failures, and silting in the ESW system, or SCs

serviced by the ESW system.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort.

Furthermore, the staff reviewed the exceptions and enhancements and their justifications to

determine whether the AMP, with the exceptions and enhancements, remains adequate to

manage the aging effects for which it is credited.

In Section B.1.29 of Appendix B to the LRA, the applicant stated that the Service Water System

Reliability Program will be consistent with GALL AMP XLI.M20 with exceptions and

enhancements. The Service Water System Reliability Program takes exception to the Scope of

Program element in that the heat exchangers may receive a thorough visual inspection and

cleaning in lieu of thermal performance testing. For the program element associated with the

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exception taken by the applicant, the GALL Report states that the guidelines of GL 89-13

include a test program to verify heat transfer capabilities. The staff reviewed the applicant's

response to GL 89-13 and determined that the applicant's use of visual inspection and cleaning

of the heat exchangers in lieu of heat transfer capability testing to ensure that the system can

perform its intended function is consistent with that which was accepted by staff in the

applicant's GL 89-13 program to manage heat exchangers. Because the staff considers the GL

89-13 program to be an acceptable basis for satisfying its expectations for GL 89-13, and

because it is consistent with the CLB, the staff finds this exception to be acceptable.

The Service Water System Reliability Program also takes exception to the Preventive Actions

program element in that the components within the scope of this program are lined or coated

only as deemed necessary to protect underlying surfaces (i.e., they are not all lined or coated).

For the program element associated with the exception taken by the applicant, the GALL

Report states that the system components are constructed of appropriate materials and lined or

coated to protect the underlying metal surfaces from exposure to aggressive cooling water

environments. The staff finds the applicant exception acceptable because the applicant 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.

Further, the Service Water System Reliability Program takes exception to the Monitoring and

Trending program element in that inspections and testing are set to commence during refueling

outages. For the program element associated with the exception taken by the applicant, the

GALL Report states that the inspection scope, method, and testing frequencies are in

accordance with the utility commitments under GL 89-13. The applicant performs testing and

inspections every refueling outage. The staff determined that the applicant's inspection

frequencies are in accordance with the its commitments under GL 89-13; therefore, the staff

finds exception to be acceptable.

The applicant stated in the LRA that it will enhance the Service Water System Reliability

Program Detection of Aging Effects program element as follows:

* The program will check for evidence of selective leaching during visual inspection.

* The applicant will develop a new preventive maintenance activity, or revise an existing

activity, to ensure that the 8-inch expansion joints in the ESW supply lines to the EDG heat

exchangers are inspected for evidence of loss of material, change in material properties,

and cracking.

RAI 3.3.2-2

The staff finds that visual inspections might not be an adequate preventive and control method

for the detection of selective leaching in all systems where it is likely to occur. GALL

AMP XL.M33, "Selective Leaching of Material," recommends a visual inspection and a hardness

measurement of selected components to determine whether the loss of material from selective

leaching is occurring. By letter dated May 6, 2004, the staff forwarded to the applicant RAI

3.3.2-2 that asked it to justify the exclusion of a hardness measurement from the Service Water

System Reliability Program to detect selective leaching. By letter dated June 8, 2004, the

applicant stated that:

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Since the detection of selective leaching is an enhancement to the Service Water

--System Reliability Program,'s pecific details on the methods for detection of selective

leaching are not available at this time. Implicit in the current commitment to enhance

the Service Water System Reliability Program is implementation using industry best

practices at the time of implementation. Current industry practices include visual

inspections and either hardness testing, as stated in NUREG-1 801, Section XL.M33,! or

other inspection methods. Additionally, in the future, more effective techniques for the

detection of selective leaching may become available.

Based on its review, the staff finds the applicant's response to RAI 3.3.2-2 acceptable. The

applicant committed to enhance the Service Water System Reliability Program using the best

industry practices at the time of implementation for the detection of selective leaching.

Therefore, the staff's concern described in RAI 3.3.2-2 is resolved. The-enhancement of the

Service Water System Reliability Program is specified in Commitment'#21 'in Appendix A of this

SER. -

The staff determined that the addition of the inspections of 8-inch expansion joirits in the'ESW

supply lines to the EDG heat exchangers is consistent with the GALL Report, On this basis,-the

staff finds the second portion of the enhancement to this program element acceptable.

RAI B. 1.29-1

In its response to RAI 3.3.2-2, the applicant stated that implicit in the original commitment

stated in the LRA to enhance the Service Water System Reliability Program is implementation

using the best industry practices at the time of implementation for the detection of selective

leaching. To be consistent with the GALL Report, hardness testing or other acceptable physical

test is recommended. The commitment did not indicate that the check for selective leaching

done during visual inspection will include hardness testing or equivalent physical testing as

recommended by the GALL Report. By letter dated February 17, 2005, the staff forwarded to

the applicant RAI B.1.29-1 asking it to clearly state if hardness testing, or an acceptable

equivalent, will be part of the program. If not, identify the exception being taken to the' GALL

Report and the basis for that exception. By letter dated March 24, 2005, the applicant include

the following commitment:

I&M will enhance the Service Water System Reliability Program to manage loss of

material due to selective leaching of susceptible materials by-visual inspections and

hardness testing or an equivalent physical test.

This is Commitment #41 in Appendix A of this'SER. Based on its review, the staff finds the

applicant's response to RAI B.1.29-1 acceptable. Therefore, the staff's concern described in

RAI B.1.29-1 is resolved.

Operating Experience The applicant stated in the LRA that its review of operating experience

for the Service Water System Reliability Program included CRs, program health reports,

procedure revisions, and LERs. It established this program to meet the requirements of GL

89-13, which includes recommendations based on'extensive industry operating experience.

Examples of aging effects noted in a report prepared by the applicant in 2002 include minor

galvanic or crevice corrosion of the component cooling water (CCW) heat exchanger

tubesheets, identified by inspection and cracking of tube seam welds, and MIC pitting of the

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containment spray heat exchangers, identified by eddy current testing. The identification of

these effects demonstrates that program activities effectively detect minor degradation before it

becomes significant.

The applicant further stated that inspections and tests performed in accordance with the

Service Water System Reliability Program have effectively identified degradation such as aging

effects that could impact the capabilities of the ESW system. When the applicant identifies

deficiencies, it performs the appropriate corrective actions. The combination of inspections and

testing is adequate to ensure that the aging effects from the exposure to ESW are adequately

managed for this system.

The staff reviewed correspondence and reports associated with the applicant's response to

GL 89-13 and subsequent activities related to the ESW system. In addition to industry

experience, the applicant has experienced significant challenges to the ESW system. The staff

reviewed a CR related to a fish kill and observed that the applicant's actions went beyond those

components directly affected by the event, leading to both the enhancement of its program to

address GL 89-13 and the discovery of numerous latent problems similar to those that are

managed by this program. The staff reviewed the applicant's document related to this program

and finds that an appropriate level of attention to plant-specific operating experience is evident.

On the basis of its review and discussions with the applicant's technical staff, the staff

concludes that the Service Water System Reliability Program adequately manages the aging

effects that have been observed at the applicant's plant.

UFSAR Suoplement

In Section A.2.1.32 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Service Water System Reliability Program. The staff reviewed this section and

determined that the information in the UFSAR Supplement adequately summarizes the program

activities. The staff finds this section of the UFSAR Supplement sufficient, pursuant to

10 CFR 54.21(d).

Conclusion

On the basis of its audit and review of the applicant's program, the staff finds that those

portions of the program for which the applicant claimed consistency with the GALL Report are

indeed consistent with the GALL Report. In addition, on the basis of its review of the

exceptions and enhancement to the GALL Report program, the staff finds that the applicant has

demonstrated that it will adequately manage the effects of aging so that the intended functions

of SCs will be maintained consistent with the CLB during 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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3.0.3.2.12 Structures Monitoring-Structures Monitoring

Summary of Technical Information in the Application

Section B.1.32, "Structures Monitoring-Structures Mohitoring," of the LRA describes the

applicant's Structures Monitoring-Structures Monitoring Program. In the LRA, the applicant

stated that this existing CNP program will be consistent, with enhahcemrients, with GALL'AMP

XI.S6, "Structures Monitoring Program."' ;

The applicant stated in the LRA that NRC RG 1.182, Revision 2, "Assessing and Managing

Risk Before Maintenance'Activities at Nuclear Power Plants," and NEI, Nuclear Management

and Resource Council (NUMARC) 93-01, Revision 2, "industry Guideline for Monitoring the'

Effectiveness of Maintenance at Nuclear Power Plants," issued April 1996, address the

implementation'of structures monitoring under 10 CFR 50.65 (the Maintenance Rule). These

two documents provide guidance for the development of licensee-specific programs' to monitor

the condition of structures and structural components within the scope of the Maintenance Rule,

such'that there'is no loss'of structure or structural component intended function.

The applicant stated that the following structures are within the scope of this program:

* containment building

* auxiliary building

* turbine building and screenhouse

* yard structures and bulk commodities

* nonsafety-related systems and components affecting safety-related systems'

The applicant will expand the program to encompass structures and structural components'

within the scope of license renewal.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this'effort.'

Furthermore, the staff reviewed the enhancements and their justifications to determine whether -

the AMP, with the enhancements, remains adequate to manage the aging effects for which it is

credited.-,

In Section B.1.32 of Appendix B of the'LRA, the applicant stated that the Structures

Monitoring-Structures Monitoring Program will be consistent with GALL AMP XL.S6 with

enhancements. The applicant will enhance the Scope of Program element to include the

supports (equipment, cable tray, conduit and pipe), instrument panels, racks, cable trays,

conduits, elastomers, pipe hangers, fire protection pump house superstructure and walls, gas

bottle storage tank rack and foundation,' security diesel generator room,-switchyard control

house, fire protection water storage tank foundation,' primary water storage tank foundation,

and roadway west of the screenhouse. The applicant will6alsoenhance the Detection of Aging

Effects program element such that the examination criteria for the roadway west of the

screenhouse must include detection of degradation of the roadway caused by weather-related

damage.

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By letter dated October 31, 2003, the applicant committed to including the additional SCs within

the scope of its Structures Monitoring-Structures Monitoring Program. This is Commitment

#23 in Appendix A of this SER. The staff finds that the proposed scope identifies the specific

components for which the program manages aging and that the additional SCs are consistent

with GALL AMP XI.S6. In addition, the enhancement to revise the procedure to include criteria

that will detect degradation of the roadway is consistent with GALL AMP XI.S6 and will ensure

that the roadway structure can perform its intended function consistent with the CLB. On this

basis, the staff finds these enhancements to be acceptable.

During its audit, the staff asked the applicant to describe how it will adequately address the

aging effects of the loss of material on the ice condenser steel structural components and the

loss of material, cracking, and changes in material properties for ice condenser concrete

structural components exposed to borated ice for the period of extended operation. The

applicant stated that its Structures Monitoring (CNP AMP B.1.32) and Boric Acid Corrosion

(CNP AMP B.1.4) Programs will ensure that the aging effects associated with the ice condenser

will be managed during the period of extended operation. Specifically, CNP AMP B.1.35,

"Structures Monitoring-Ice Basket Inspection," addresses the ice baskets. The staff finds this

acceptable.

Operating Experience The applicant stated in the LRA that its operating experience review

included CRs, LERs, NRC inspection reports, peer assessments, and self-assessments. The

most recent NRC inspection of the Maintenance Rule implementation of the Structures -

Monitoring Program, conducted in 2001 (NRC Inspection Report, 50-315/01-16 and 50-316/01-

16, October 16, 2001), identified no findings of significance for the specific areas related to the

Maintenance Rule that were inspected.

The staff reviewed the self assessments related to the Structures Monitoring Program that were

conducted in 1999 and 2001. Based on those self assessments, the applicant identified

corrective actions which included revising the Structures Monitoring Program controlling

procedure to incorporate the specific acceptance criteria recommended by the 2001 selfassessment. The applicant, during the self-assessment, identified another corrective action

related to the fact that several miscellaneous structures were not addressed by the Structures

Monitoring Program. The program controlling procedure was revised to include these

miscellaneous structures.

On the basis of its review of the above operating experience and on discussions with the

applicant's technical staff, the staff concludes that Structures Monitoring-Structures Monitoring

Program adequately manages the aging effects that have been observed at the applicant's

plant.

UFSAR SuDplement

In Section A.2.1.35 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Structures Monitoring-Structures Monitoring Program. The staff reviewed this section

and determined that the information in the UFSAR Supplement adequately summarizes the

program activities. The staff finds this section of the UFSAR Supplement sufficient, pursuant to

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 those

attributes of the program for which the applicant claimed consistency with the GALL Report are

indeed consistent with the GALL Report. In addition, the staff has reviewed the enhancements

to the GALL Report program and finds that the applicant has demonstrated that it will

adequately manage the effects of aging so that the intended functions of SCs 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).

3.0.3.2.13 Structures Monitoring-Crane Inspection

Summary of Technical Information in the Application

Section B.1.33, 'Structures Monitoring-Crane Inspection," of the LRA describes the'applicant's

Structures Monitoring-Crane Inspection Program. In the LRA, the applicant stated that this

existing CNP program will be consistent, with exceptions and enhancements, with GALL

AMP XL.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems."

The applicant stated in the LRA that this program includes testing and monitoring to provide

assurance that the SSCs of these cranes are capable of sustaining their rated loads. This

program is primarily concerned with passive structural components that make up the bridge and

trolley.

Staff Evaluation -

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. .The audit and review report documents the staff's evaluation of this effort.-

Furthermore, the staff reviewed the exceptions and enhancements and their justifications to

determine whether the AMP, with the exceptions and enhancements, remains adequate to -

manage the aging effects for which it is credited.

In Section B.1.33 of Appendix B to the LRA, the applicant stated that the Structures

Monitoring-Crane Inspection Program will be consistent with GALL AMP XL.M23 with

exceptions and enhancements. The program takes exception to the Parameters Monitored or

Inspected program element in that it does not review the number and magnitude of the lifts.

For the program element associated with the exception taken by the applicant, the GALL

Report states that the number and magnitude of lifts made by the crane are reviewed. The

staff finds that review of the number and magnitude of lifts is not necessary since the allowable

limits are expected to provide adequate margin for the period of extended operation. Section

4.7.6 of the LRA addresses the number of lifts-made by cranes as-a time-limited aging analysis

(TLAA). On this basis, the staff finds this exception to be acceptable.

The Structures Monitoring-Crane Inspection Program also takes exception to the Detection of

Aging Effects program element in that it does not perform functional tests on all in-scope

cranes. For the program element associated with the exception taken by the applicant, the

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GALL Report states that crane rails and structural components are visually inspected on a

routine basis for degradation. Functional tests are also performed to assure their integrity.

During the audit, the staff found that the intended function of many cranes is maintaining

structural integrity to prevent impacting safety-related SSCs. Therefore, functional tests

involving the active components of these cranes are not subject to aging management. On this

basis, the staff finds the functional part of the exception to be acceptable.

Section 4.7.6 of this SER describes the staff evaluation of the exception that validates the

structural integrity of crane components through visual inspection in lieu of functional tests.

The applicant stated in the LRA that it will enhance the Structures Monitoring-Crane

Inspection Program Scope of Program element by developing procedures or recurring tasks to

manage the loss of material on the crane, rails, and supports of in-scope cranes. The staff

finds that the addition of procedures or recurring tasks to manage the loss of material on

in-scope components is consistent with the requirements for this program element in GALL

AMP XI.M23. On this basis, the staff finds this enhancement to be acceptable.

The applicant stated in the LRA that it will enhance the Structures Monitoring-Crane

Inspection Program Parameters Monitored or Inspected program element by developing

procedures or recurring tasks to evaluate the effectiveness of the maintenance monitoring

program and the effects of past and future usage on the structural reliability of in-scope cranes.

The staff finds that addition of procedures or recurring tasks to evaluate the effectiveness of the

maintenance monitoring program and the effects of past and future usage on the structural

reliability of cranes is consistent with the requirements for this program element in GALL AMP

XI.M23. On this basis, the staff finds this enhancement to be acceptable.

The applicant stated in the LRA that it will enhance the Structures Monitoring-Crane

Inspection Program Detection of Aging Effects program element by developing procedures or

recurring tasks to verify that in-scope crane rails and structural components are visually

inspected on a routine basis for loss of material. The staff finds that the addition of procedures

or recurring tasks to visually inspect crane rails and structural components for degradation on a

routine basis is consistent with the requirements for this program element in GALL

AMP XI.M23. On this basis, the staff finds this enhancement to be acceptable.

The applicant stated in the LRA that it will enhance the Structures Monitoring-Crane

Inspection Program Acceptance Criteria program element by developing procedures or

recurring tasks to verify that significant visual indications of the loss of material from corrosion

or wear are evaluated according to applicable industry standards and good industry practice.

The staff finds that the addition of procedures or recurring tasks to evaluate significant visual

indications of degradation according to applicable industry standards and good practice is

consistent with the requirements for this program element in GALL AMP XI.M23. On this basis,

the staff finds this enhancement to be acceptable. These enhancements to the Structures

Monitoring-Crane Inspection Program are part of Commitment #24 in Appendix A of this SER.

Operatina Experience The applicant states in the LRA that its operating experience review

included a review of CRs, LERs, NRC inspection reports, and self-assessments.

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The staff reviewed operating experience relative to the Structures Monitoring-Crane

Inspection Program and did not identify any crane aging problems. One industry operating

experience incident identified involved a crane rail stud failure caused by fatigue. As the

corrective action, the applicant had the crane representative inspect major cranes and modified

the preventive maintenance task sheet to ensure that inspections are performed before crane.

use.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that Structures Monitoring-Crane Inspection

Program adequately manages the aging effects that have been observed at the applicant's

plant or at other nuclear facilities.

UFSAR Supplement

In Section A.2.1.36 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Structures Monitoring-Crane Inspection Program. The staff reviewed this section and

determined that the information in the UFSAR Supplement adequately summarizes the program

activities. The staff finds this section of the UFSAR Supplement sufficient, pursuant to

10 CFR 54.21 (d).

Conclusion.

On the basis of its review and audit of the applicant's program, the staff finds that those

attributes of the program for which the applicant claimed consistency with the GALL Report are

indeed consistent with the GALL Report. In addition, the staff has reviewed the exceptions and

enhancements to the GALL Report program and finds that the applicant has demonstrated that

it will adequately manage the effects of aging so that the intended functions of SCs 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).

3.0.3.2.14 Structures Monitoring-Masonry Wall

Summary of Technical Information in the Application

Section B.1.36, "Structures Monitoring-Masonry Wall," of the LRA describes the applicant's

Structures Monitoring-Masonry Wall Program. In the LRA, the applicant stated that this

existing CNP program will be consistent, with an enhancement, with GALL AMP XI.S5,

"Masonry Wall Program."

The applicant stated in the LRA that the Masonry Wall Program manages aging effects so that

the evaluation basis established for each masonry wall within the scope of license renewal

remains valid through the period of extended operation. The applicant inspects masonry walls

as part of the Structures Monitoring Program conducted for the Maintenance Rule,

10 CFR 50.65.

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Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort.

Furthermore, the staff reviewed the enhancement and its justifications to determine whether the

AMP, with the enhancement, remains adequate to manage the aging effects for which it is

credited.

In Section B.1.36 of Appendix B to the LRA, the applicant stated that it will enhance the Scope

of Program element for the Structures Monitoring-Masonry Wall Program to include the 4-hour

fire rated masonry block in the turbine building and screenhouse, and the masonry block in the

auxiliary building. For the program element associated with the enhancement by the applicant,

the GALL Report states that the scope includes all masonry walls identified as performing

intended functions in accordance with 10 CFR 54.4. The staff finds that the inclusion of the

masonry block in the turbine building, screenhouse, and auxiliary building is consistent with the

GALL Report. The applicant identified these structural components as within the scope of

license renewal because they perform intended functions in accordance with 10 CFR 54.4. On

this basis, the staff finds the enhancement to be acceptable. This enhancement is Commitment

#25 in Appendix A of this SER.

Operating Experience The applicant stated in the LRA that the operating experience review for

the Structures Monitoring-Masonry Wall Program included CRs, NRC inspection reports, and

documentation of the results of internal program assessments.

The applicant stated in the LRA that it identified physical degradation during a walkdown in

1999. Three block walls had mortar joints that were cracked and needed to be resealed. As a

result of these findings, the applicant conducted additional inspections for loss of function (but

did not find any) and repaired the three walls. This demonstrates that activities performed

under the program actively identify and manage aging effects before loss of function.

Based on a review of the applicant's CRs, the staff concludes that the applicant has identified

operating experience for the Structures Monitoring-Masonry Wall Program and has performed

corrective actions where needed.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the Structures Monitoring-Masonry Wall

Program adequately manages the aging effects that have been observed at the applicant's

plant.

UFSAR Supplement

In Section A.2.1.39 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Structures Monitoring-Masonry Wall Program. The staff reviewed this section and

determined that the information in the UFSAR Supplement adequately summarizes the program

activities. The staff finds this section of the UFSAR Supplement sufficient, pursuant to

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 those -

attributes of the program for which the applicant claimed consistency with the GALL Report are

indeed consistent with the GALL Report. In addition, the staff has reviewed the enhancement

to the GALL Report program and finds that the applicant has demonstrated that it will

adequately manage the effects of aging so that the intended functions of SCs 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).

3.0.3.2.15 Water Chemistry Control-Primary and Secondary Water Chemistry Control

Summary of Technical Information in the Application

Section B.1.40.1 of the LRA describes the applicant's Water Chemistry Control-Primary and

Secondary Water Chemistry Control Program. In the LRA, the applicant stated that this -

existing CNP program will be consistent, with enhancements, with GALL AMP XI.M2, "Water

Chemistry."

The applicant stated in the LRA that this program mitigates damage caused by corrosion and

stress-corrosion cracking (SCC). The program relies on monitoring and control of water

chemistry based on Electric Power Research Institute (EPRI) guidelines.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. -The audit and review report documents the staff's evaluation of this effort. -

Furthermore, the staff reviewed the enhancements and their justifications to determine whether

the AMP, with the enhancements, remains adequate to manage the aging effects for which it is

credited.

In Section B.1.40.1 of Appendix B to the LRA, the applicant stated that the Water Chemistry

Control-Primary and Secondary Water Chemistry Control Program will be consistent with

GALL AMP XL.M2 with enhancements. The applicant stated in the LRA that it will enhance the

Water Chemistry Control-Primary and Secondary Water Chemistry Control Program

Parameters Monitored or Inspected program element by revising program controlling*

procedures to require individual implementing procedures to identify and prescribe any special

collection and preservation procedures to collect a sample. The applicant stated that it will also

enhance the Acceptance Criteria program element to include sulfate monitoring criteria for the

refueling water storage tank (RWST) that are consistent with the EPRI guidelines and the

sulfate criteria for other systems impacted by RWST chemistry (i.e., RCS and SFP).

Furthermore, the applicant will enhance the Parameters Monitored or Inspected and

Acceptance Criteria program elements according to the applicable EPRI water chemistry

guidelines. -

The staff finds that the enhancements to the Water Chemistry Control-Primary and Secondary

Water Chemistry Control Program, all of which are intended to ensure that the program

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complies with the applicable EPRI water chemistry guidelines and thus ensure consistency with

the GALL AMP, will improve the ability of the systems to perform their intended functions

consistent with the CLB during the extended operating term. On this basis, the staff finds the

enhancements to be acceptable.

OperatinQ Experience The applicant stated in the LRA that the program is based on the EPRI

water chemistry guidelines, which reflect chemistry practices based on operating experience in

the nuclear power industry. The guidelines are updated as appropriate based on continuing

operating experience.

The applicant stated in the LRA that it performed a primary chemistry self-assessment in 2002

that focused on critical program attributes. It evaluated selected attributes established in EPRI

PWR primary water guidelines. The assessment included an industry peer and obtained

benchmarking information from two other plants. The assessment team concluded that the

essential program attributes assessed are adequately described and effectively implemented.

The applicant also stated in the LRA that it performed a self-assessment of the secondary

chemistry program in 2002, including peer review with staff from another station, to identify

program deficiencies and to establish corrective actions. The assessment team examined

industry operating experience to improve startup contaminant control. The assessment team

concluded that the essential program attributes assessed are adequately described and

effectively implemented.

The staff reviewed the applicant's documentation and concludes that the applicant has

identified operating experience for the Water Chemistry Control-Primary and Secondary

Water Chemistry Control Program and performed corrective actions where needed.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the Water Chemistry control-Primary and

Secondary Water Chemistry Control Program adequately manages the aging effects that have

been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.43 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Water Chemistry Control-Primary and Secondary Water Chemistry Control Program.

The staff reviewed this section and determined that the information in the UFSAR Supplement

adequately summarizes the program activities. The staff finds this section of the UFSAR

Supplement sufficient, pursuant to 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

attributes of the program for which the applicant claimed consistency with the GALL Report are,

indeed, consistent with the GALL Report. In addition, the staff has reviewed the enhancements

to the GALL Report program and finds that the applicant has demonstrated that it will

adequately manage the effects of aging so that the intended functions of SCs 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

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that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.16 Water Chemistry Control-Closed Cooling Water Chemistry Control

Summary of Technical Information in the Application

Section B.1.40.2 of the LRA describes the applicant's Water Chemistry Control-Closed

Cooling Water Chemistry Control Program. In the LRA, the applicant stated that this existing

CNP program will be consistent with GALL AMP XI.M21, "Closed-Cycle Cooling Water System,"

with exceptions.

The applicant stated in the LRA that this program includes preventive measures that manage

loss of material (including that caused by selective leaching, where applicable); cracking, and

fouling, as applicable, for closed cooling water system components. These chemistry activities

provide for monitoring and controlling closed cooling water chemistry using procedures and -

processes that are based on EPRI TR-107396, "Closed Cooling Water Chemistry Guidelines."

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The audit and review report documents the staff's evaluation of this effort. -

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 Section B.1.40.2 of Appendix B to the LRA, the applicant stated that the Water Chemistry

Control-Closed Cooling Water Chemistry Control Program will be consistent with GALL AMP

XL.M21 with exceptions. The Water Chemistry Control-Closed Cooling Water Chemistry --

Control Program takes exception to the Parameters Monitored or Inspected, Monitoring and

Trending, and Acceptance Criteria program elements in that the program only monitors

chemistry parameters. For the program elements associated with the exception taken by the

applicant, the GALL Report states that the AMP monitors the effects of corrosion by

surveillance testing and inspection in accordance with.the 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. Performance and

functional tests are performed at least every 18 months to demonstrate system operability.

Tests to evaluate heat removal capability of the system and degradation of system components

are performed every 5 years. System and component performance test results are evaluated in

accordance with the guidelines of EPRI TR-107396. -Acceptance criteria and tolerances are

also based on system design parameters and functions.

During the audit, the staff asked the applicant to justify the acceptability of the exception to

these program elements (Parameters Monitored or Inspected, Monitoring and Trending, and

Acceptance Criteria) in GALL AMP XL.M21. The applicant stated that monitoring only the

chemistry parameters is sufficient to protect system components from degradation without

monitoring the parameters of pumps and heat exchangers in the system.

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In its response, the applicant stated that EPRI TR-107386 does not provide specific

recommendations for equipment performance and functional testing at a given frequency 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. Section 5.7 of EPRI TR-1 07396 states that

performance monitoring is typically part of an engineering program, which would not be part of

water chemistry. In addition, EPRI TR-107386 further states 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 operating experience and inspection procedures of plant

systems and heat exchangers together with industry guidelines and determined that there is

reasonable assurance that monitoring chemistry parameters in conjunction with plant

inspections will adequately manage aging effects on the closed cycle cooling water systems.

On this basis, the staff finds this exception to be acceptable.

In addition, the Water Chemistry Control-Closed Cooling Water Chemistry Control Program

takes exception to the Detection of Aging Effects program element by stating that it is a

preventive program that claims no credit for the detection of aging effects through performance

and functional testing. For the program element associated with the exception taken by the

applicant, the GALL Report states that the extent and schedule of inspections and testing, in

accordance with EPRI TR-107396, assure the detection of corrosion before the loss of intended

function of the component. Performance and functional testing, in accordance with EPRI

TR-1 07396, ensures the acceptable functioning of the closed cooling water system or

components serviced by the closed cooling water system.

During the audit, the staff asked the applicant to justify the exception to the Detection of Aging

Effects program element in GALL AMP XL.M21 and explain why performance and functional

testing is not required to effectively manage aging effects.

In its response, the applicant stated that, in most cases, functional and performance testing

verifies that component active functions are maintained and therefore would be managed by the

Maintenance Rule (10 CFR 50.65). The applicant further responded that GL 89-13 does not

require testing of closed cycle cooling water system heat exchangers because of the

effectiveness of the Closed Cooling Water Chemistry Control Program. The Closed Cooling

Water Chemistry Control Program will adequately manage the passive intended functions of

pumps, heat exchangers, and other components of the closed cycle cooling water system.

The staff reviewed the applicant's response and operating experience and concludes that aging

effects on passive mechanical components in the closed cooling water system are adequately

managed without reliance on performance and functional testing. On this basis, the staff finds

the exception to the Detection of Aging Effects program element to be acceptable.

Lastly, the Water Chemistry Control-Closed Cooling Water Chemistry Control Program takes

exception to the Acceptance Criteria program element such that the nitrite corrosion inhibitor

concentrations are maintained within specified limits, which allow for a larger variance

(1200-4000 parts per million (ppm)) than recommended (500-1000 ppm) in EPRI TR-107396.

For the program element associated with the exception taken by the applicant, the GALL

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Report states that corrosion inhibitor concentrations are maintained within the limits specified in

the EPRI water chemistry guidelines for closed cooling water systems.

During the audit, the staff asked the applicant to provide the technical basis for using different -

limits than EPRI TR-1 07396 on .nitrite corrosion inhibitor concentrations and to justify that its

concentration limits will not increase the probability of corrosion in system components.'_''

In its response, the applicant stated that EPRI TR-1 07396, Section 4.3.2, notes the following:

Based on industry experience, lower ranges (200 to 500 ppm) have been successfully

used in systems with demineralized water makeup. Higher levels (up to 4000 ppm) can

be used, but increase the potential for microbiological growth. . - : --

The applicant further stated that procedural targets for nitrites are within these EPRI guidelines,

and that CNP AMP B.1.41, "Water Chemistry Control-Chemistry One-Time Inspection," will

confirm the effectiveness of.the Closed Cooling Water Chemistry Control Program before the'

period of extended operation. Additionally, the applicant has converted water chemistry control

for.component cooling water systems to molybdate corrosion inhibitor control, and the limits for

molybdate match the recommended limits in EPRI TR-107396. The applicant has stated that

nitrate control remains a procedural option until sufficient operating experience with molybdate

control is evaluated. -

The staff reviewed the Water Chemistry Control-Chemistry One-Time Inspection Program and

documents its evaluation in Section 3.0.3.3.17 of this SER.

The staff reviewed the applicant's response, operating experience (discussed below), and

industry guidelines and determined that there is reasonable assurance that monitoring these

nitrite corrosion inhibitor concentrations within specified limits will adequately manage aging

effects on closed cooling water systems. On this basis, the staff finds this exception to the

Acceptance Criteria program element to be acceptable.

Operating Experience The applicant stated in the LRA that its operating experience for the

Water Chemistry Control-Closed Cooling Water Chemistry Control Program reflects chemistry'

practices based on extensive operating experience in the nuclear industry. The guidelines areupdated, as appropriate, based on continuing operating experience. An independent

assessment, performed by the applicant in 1999, of the component cooling water system

chemistry included a detailed review of the program chemical selection, control, monitoring, and

recordkeeping and provided an examination of the fidelity of the processes with industry

guidance documents.

The applicant further stated that the independent review provided evaluations of plant-specific

operating experience and recommendations based on that experience. The review found the'

documentation of the chemical treatment processes to be exemplary, while the overall program

is comparable to industry best practices. -

The staff reviewed operating experience in representative CRs relevant to the Water

Chemistry-Closed Cooling Water Chemistry Control Program and finds that the program

monitors and corrects out-of-specification readings before they contribute to the aging of

components.

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On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the Water Chemistry Control-Closed Cooling

Water Chemistry Control Program adequately manages the aging effects that have been

observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.44 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Water Chemistry Control-Closed Cooling Water Chemistry Control Program. The staff

reviewed this section and determined that the information in the UFSAR Supplement

adequately summarizes the program activities. The staff finds this section of the UFSAR

Supplement sufficient, pursuant to 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

attributes of the program for which the applicant claimed consistency with the GALL Report are

indeed consistent with the GALL Report. In addition, the staff has reviewed the exceptions to

the GALL Report program and finds that the applicant has demonstrated that it will adequately

manage the effects of aging so that the intended functions of SCs 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).

3.0.3.2.17 Fatigue Monitoring

Summary of Technical Information in the Application

Section B.2.2, "Fatigue Monitoring,' of the LRA describes the applicant's Fatigue Monitoring

Program. In the LRA, the applicant stated that this existing program is consistent, with an

exception, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." The

applicant stated that in order to remain within fatigue usage design limits, the Fatigue

Monitoring Program monitors and tracks the number of critical thermal and pressure transients

for selected RCS components. The program ensures the validity of analyses that explicitly

assume a specified number of thermal and pressure fatigue transients. This program manages

those components that are shown to be acceptable by analyses explicitly based on a limiting

number of thermal or pressure fatigue transient cycles.

In addition, the applicant stated, in the LRA, that the Fatigue Monitoring Program for aging

management is a continuation of an existing program. The projections from the plant operating

experience to 60 years of operation show that the fatigue transients will be within bounds for the

extended license of the plant. The applicant also states that continued implementation of the

Fatigue Monitoring Program will assure that the applicable SCs will be monitored for fatigue

damage and will perform their intended functions within the design basis during the extended

period of 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. The audit and review report documents the staff's evaluation of this effort."

Furthermore, the staff reviewed the exception and its justifications to determine whether the

AMP,,with the exception, remains adequate to manage the aging effects for which it is credited.

In Section B.2.2 of Appendix B of the LRA, the applicant stated that the Fatigue Monitoring

Program is consistent with GALL-AMP XI.M1 with an exception; The Fatigue Monitoring

Program takes exception to the Detection of Aging Effects program element in that the program

does not provide for periodic update of fatigue usage calculations. The program initiates

corrective actions only when the number of accumulated cycles approaches 80 percent of the

number of component design cycles.

The GALL Report states that the program provides for the periodic update of the fatigue usage

calculations. The applicant 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 it commited to implement corrective

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

exception in the Fatigue Monitoring Program is acceptable. -

Operating ExDerience The applicant stated in the LRA that it performed a self-assessment of

the Fatigue Monitoring Program in 1999. This self-assessment identified deficiencies and

provided recommendations that were addressed with CRs. These CRs led to enhancements of

the implementing procedure, even though the procedure met the intent of the program

requirements. The applicant also stated that, in 2002, it performed a followup self-assessment

to review the program improvements. This followup self-assessment concluded that the*

program will adequately and accurately track design-basis plant transients. This assessment

also identified deficiencies and provided recommendations that were addressed by corrective

actions, which demonstrates that the program continues to be monitored and improved.

In addition, the applicant stated that it has tracked thermal fatigue transients since the initial

hydrostatic tests and commercial operation of both CNP units. The applicant stated that it

performed a review of the number of design transients documented to date. Based on the rate

of occurrence, it projected the numbers of the various transients to 60 years of operation. The

applicant demonstrated that the numbers of design transients projected for the period of

extended operation associated with license renewal are less than the numbers of transients

considered in its fatigue analyses. -

The staff reviewed the applicant's documentation and concludes that the applicant has

identified operating experience for the Fatigue Monitoring Program and performed corrective

actions, where needed.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that CNP AMP B.2.2 is sufficient to support the

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management of the aging effects of fatigue that have been monitored and predicted at the

applicant's plant.

UFSAR Supplement

In Section 2.1.12 of Appendix A to the LRA, the applicant provided its UFSAR Supplement for

the Fatigue Monitoring Program. The staff reviewed this section and determined that the

information in the UFSAR Supplement adequately summarizes the program activities. The staff

finds this section of the UFSAR Supplement sufficient, pursuant to 10 CFR 54.21 (d).

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that those

attributes of the program for which the applicant claimed consistency with the GALL Report are, indeed, consistent with the GALL Report. In addition, the staff has reviewed the exception to

the GALL Report program and finds that the applicant has demonstrated that it will adequately

manage the effects of aging so that the intended functions of SCs 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 to the LRA, the applicant indicated that the following AMPs are plant specific:

* Alloy 600 Aging Management Program

* Bolting and Torquing Activities Program)

* Boral Surveillance Program

* Bottom-Mounted Instrumentation Thimble Tube Inspection Program * Heat Exchanger Monitoring Program

* Inservice Inspection-ASME Section Xl, Augmented Inspection Program * Instrument Air Quality Program

* Oil Analysis Program

* Pressurizer Examinations Program

* Preventive Maintenance Program

* Structures Monitoring-Divider Barrier Seal Inspection Program * Structures Monitoring-Ice Basket Inspection Program * System Testing Program

* System Walkdown Program

* Wall Thinning Monitoring Program

* Water Chemistry Control-Auxiliary Systems Water Chemistry Control Program * Water Chemistry Control-Chemistry One-Time Inspection Program

For the plant-specific 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 are adequate to monitor

or manage aging. The following sections of this SER document the staff's review of these

plant-specific AMPs.

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3.0.3.3.1 Alloy 600 Aging Management;

Summary of Technical Information in the Application

Section B.1.1 of Appendix B to the LRA discusses the'Alloy 600 Aging Management Program.

The applicant stated that the Alloy 600 Aging Management Program is a new, plant-specific

program that it will implement before the period of extended operation. There is no comparable

GALL Report program. The applicant stated that this' program'will manage the aging effects of

Alloy 600/690 components and Alloy 52/152 and 82/182 welds in the RCS that are'not

addressed by other AMPs. This program will detect primary water stress corrosion cracking

(PWSCC) before the loss of the component intended function by using the examination and

inspection requirements specified in ASME Code, Section XI.

Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the Alloy 600 Aging Management

Program to determine if the program demonstrates that it will adequately manage aging effects

so that the component intended functions will be maintained consistent with the CLB for the

period of extended operation.

In LRA Section A.2.1.1, the applicant stated that it will implement the new Alloy 600 Aging

Management Program before the period of extended operation. The Alloy 600 Aging

Management Program will detect cracking from PWSCC by using the examination and

inspection requirements specified in ASME Code, Section XI. This program excludes -

components which are covered by the following AMPs:

* Control Rod Drive Mechanism and Other Vessel Hea'd Penetration Inspection Program

* Steam Generator Integrity Program

* Reactor Vessel Internals Programs

RAI B. 1.1.2-1

The applicant's commitment does not identify that the lessons learned from industry initiatives

and research will become part of the Alloy 600 Aging Management Program., Since the

applicant's program has not been developed, the applicant has not demonstrated that the Alloy

600 Aging Management Program will identify and assist in managing the effects of age-related

degradation mechanisms (ARDMs).- Therefore; in RAI B.1.1.2-1 dated July 2, 2004,' the staff

requested the following:

The staff requests the applicant to modify commitment A.2.1.1 and the Program:

Description to state that lessons learned from industry initiatives and research will be'

used as part of the Alloy 600 Aging Management Program. The commitment needs to

state that the Alloy 600 Aging Management Pro'gram will be submitted for staff review

-and approval three years prior to the period of extended operation to determine if the

program demonstrates an ability to manag'e the effects of aging per

10 CFR 50.54.21(a)(3).

In its supplemental letter dated August 11, 2004, the applicant's response to RAI B.1 .1.2-1

states that, in the Monitoring and Trending program element, the applicant will use'guidance

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developed by the EPRI MRP and the owners groups to identify critical locations for inspection

and augment existing ISI at CNP, where appropriate. Similarly, in the Operating Experience

program element, the LRA states that the applicant will consider industry and plant-specific

operating experience in the development of this program as appropriate. The applicant

committed to implement a new Alloy 600 Aging Management Program. This is Commitment #3

in Appendix A of this SER, which states:

I&M will continue to participate in industry initiatives, such as Westinghouse Owners

Group and the EPRI/MRP. Susceptibility rankings and program inspection requirements

regarding Alloy 82/182 pipe butt welds will be consistent with the later version of the

EPRI MRP safety assessment or its successors.

The applicant revised the last paragraph of LRA Section A.2.1.1. This revision is part of

Commitment #1 in Appendix A of this SER and is as follows:

The Alloy 600 Aging Management Program will detect cracking from primary water

stress corrosion cracking (PWSCC) using the examination and inspection requirements

in ASME Section Xl. Guidance developed by the EPRI Materials Reliability Program

and the owners groups will be used to identify susceptibility rankings and program

inspection requirements regarding Alloy 82/182 pipe butt welds. This program will be

implemented prior to the period of extended operation.

The applicant stated that it will also revise the Alloy 600 Aging Management Program

commitment to indicate that it will submit an inspection plan for staff review and approval

3 years before the period of extended operation to determine if the program demonstrates the

ability to manage the effects of aging in accordance with 10 CFR 54.21 (a)(3). This is

Commitment #2 in Appendix A of this SER.

The staff concludes that the commitments made in response to RAI B.1.1.2-1 will ensure

implementation of the appropriate changes (i.e., those that assure the structural integrity of the

RVHs and other Alloy 600 components in the primary coolant system during the extended

period of operation). Therefore, the staff considers RAI B.1.1.2-1 closed.

The staff reviewed the program against the 10 elements that are described in Appendix A to the

SRP-LR.

Scope of Program The applicant stated that the Alloy 600 Aging Management Program scope

includes Alloy 600/690 components and Alloy 52/152 and 82/182 welds in the RCS that other

AMPs do not address. The applicant identified the specific SCs that this program would

manage. This element is acceptable to the staff because the program will address Alloy 52/152

and 82/182 welds that other AMPs do not address.

Preventive Actions The applicant identified this element as a condition monitoring program.

Therefore, the identification of preventive actions is not required. This element is acceptable to

the staff because it agrees with the licensee that this is a condition monitoring program.

Parameters Monitored or Inspected The applicant stated that the Alloy 600 Aging Management

Program will detect degradation by using the examination and inspection requirements

specified in ASME Code, Section Xl. It will monitor the presence and extent of cracking. This

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element is acceptable to the staff because the licensee will use the inspection and examination

requirements specified in ASME Code, Section Xl.

RAI B. 1. 1.2-2

Detection of Aging Effects The applicant stated that the Alloy 600 Aging Management Program

will detect cracking by PWSCC before the loss of the component intended functions The

components will receive a volumetric examination during each inspection interval in accordance

with the 1989 edition of ASME Code, Section Xl, Examination Category B-F. Therefore, in RAI'

B.1.1.2-2 dated July 2, 2004, the staff requested the following:

The staff requests the applicant to provide justification, including codes and standards

referenced, that the technique and frequency used in the Alloy 600 Aging Management

Program are adequate to detect the aging effects before a loss of system or component

function occurs.

In its supplemental letter dated August 11, 2004, the applicant's response to RAI B.1.1.2-2

stated that the inspection techniques and frequencies for the components that will be included

in the Alloy 600 Aging Management Program and that will receive volumetric inspection are

those described in ASME Code, Section Xl, Examination Category B-F. The applicant also

stated that dissimilar metal welds subject to volumetric inspections in each inspection interval

will meet the flaw acceptance criteria defined in ASME Code, Section Xl, Subsection IWB-3514.

The applicant also stated that the Scope of Program element in LRA Section B.1.1 describesthe reactor vessel, pressurizer, and steam generator components that will be included in the

Alloy 600 Aging Management Program. The program will include the consideration of industry

operating experience in developing the inspection frequency, techniques, and acceptance':

criteria. For example, NRC Bulletin 2003-02 details industry experience with leaking reactor'

lower head penetrations fabricated from nickel-based alloy material. The NRC issued Bulletin

2004-01 in May 2004. These recent bulletins indicate the evolving nature of regulatory guidance

related to Alloy 600 materials.

The applicant stated that the aging of Alloy 600 is an issue relevant to current plant operation.

In accordance with the license renewal principles 'discussed in the SOC for the final rule for

10 CFR Part 54, the existing regulatory process, which includes consideration of industry -

operating experience, will ensure that the Alloy 600 Aging Management Program can effectively

manage the cracking of Alloy 600 material from PWSCC. -

The licensee stated that it will base the development of the Alloy 600 Aging Management

Program inspection techniques-and frequencies on ASME Code, Section'XI, current and

ongoing industry operating experience and the existing regulatory process.

The staff concludes that the clarifications made in the response to RAI B.1.1.2-2 will ensure the

implementation of the appropriate changes (i.e., those that assure the structural integrity of the'

RVHs and other Alloy 600 components in the'primary coolant system during the extended

period of operation). Therefore, the staff considers RAI B.1.1.2-2 closed. -

Monitoring and Trending The applicant stated that it will maintain inspection records,

examination and test procedures, examination/test data, and corrective actions taken or

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recommended in accordance with the requirements of ASME Code, Section Xl, Subsection

IWA.

The applicant stated that the EPRI MRP, in conjunction with the PWR owners groups, is

developing a strategic plan to manage and mitigate PWSCC of nickel-based alloy items. As its

main goal, the MRP provides short- and long-term guidance for inspection, evaluation, and

management of Alloy 600 base material and Alloy 52/152 and 82/182 weld metal locations in

PWR primary systems. The applicant stated that it expects to use the guidance developed by the MRP and owners groups to identify critical locations for inspection and augment existing ISI

inspections at CNP as appropriate.

Acceptance Criteria The applicant stated that the acceptance criteria for volumetric and visual

inspections will be based upon the requirements in ASME Code, Section Xl.

RAI B. 1.1.2-3

At a minimum, 10 CFR 50.55a requires the applicant to comply with the flaw acceptance criteria

specified for ASME Class 1 components in ASME Code, Section Xl, Subsections IWA-3000

and IWB-3000, regardless of whether the material is fabricated from Alloy 600. The applicant

may use alternative acceptance criteria determined either by the applicant or the industry if the staff has reviewed and accepted the alternative criteria pursuant to 10 CFR 50.55a(a)(3). The

acceptance criteria stated are not definitive enough to determine if the applicant would allow

pressure boundary leakage if the fracture mechanics analysis proved that the component could perform its intended function. Therefore, in RAI B.1.1.2-3 dated July 2, 2004, the staff

requested the following actions of the applicant:

The staff requests the applicant to discuss the process for calculating specific numerical

values of conditional acceptance criteria to ensure that the structure and component intended functions will be maintained under all CLB design conditions. The discussion

needs to focus on how pressure boundary leakage due to PWSCC will be handled.

In its supplemental letter dated August 11, 2004, the applicant's response to RAI B.1.1.2-3

stated the acceptance criteria for volumetric inspections of dissimilar metal weld (Alloy 82/182) locations, as required by ASME Code, Section Xl, Examination Category B-F, will be in

accordance with ASME Code, Section IX, Subsection IWB-3514. The applicant stated that ASME Code, Section Xl, Subsection IWB-3514.4, discusses allowable flaw standards for

dissimilar metal welded joints and references allowable flaw standards for austenitic piping in

Table IWB-3514-2. Section J of EPRI NP-1406-SR, 'Nondestructive Examination Acceptance Standards," issued May, 1980, contains the flaw acceptance standards for austenitic piping in

ASME Code, Section Xl, Table IWB-3514-2, which are based on the net-section ductile yielding criterion. The applicant stated that the allowable flaw sizes in ASME Code, Section Xl, Table IWB-3514-2, are based on the net-section ductile yielding criterion, since linear elastic fracture

mechanics could not be used without modifications to account for plastic effects, and

elastic-plastic fracture analysis was not fully developed when ASME Code, Section Xl, Table

IWB-3514-2, acceptance standards were developed. The applicant stated that leakage is not permitted regardless of flaw size.

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The applicant continued by stating the following:

I&M will continue to participate in industry initiatives, such as the Westinghouse Owners

Group and the'EPRI MRP. Susceptibility rankings and program inspection requirements

regarding Alloy 82/182 pipe butt welds will be consistent with the later version of the

EPRI MRP safety assessment or its successors. Through the use of operating'-

experience; shoiuld the industry develop alternative acceptance criteria for ASME Code,

Section Xi, Category B-F, based on the EPRI MRP regarding inspection of dissimilar

metal welds, I&M will evaluate applicability to CNP and implement the pertinent

acceptance criteria accordingly.

The applicant stated that unacceptable indications require detailed analysis, repair, or

replacement. The acceptance standards established in ASME Code, Section Xl, Subsection

IWB-3500, ensure that all service conditions (A through D) are protected by maintaining the

safety margin'of the component throughout the service life of the component. When the

applicant is evaluating an operating component for an indication that it exceeds the allowable'

acceptance standards in Subsection IWB-3500, it refers to Section Xl and requires the use of

the original safety margins for all operating conditions (i.e., normal, upset, emergency, and

faulted conditions). The applicant stated the safety margins vary for specific cases (i.e.'

component and geometry) but are always consistent or conservative with respect to the original

design margins.

The applicant stated that should additional nickel-based alloy locations (weld and base metal)

be identified for inspection (volumetric, surface, or visual) based on industry operating

experience, for which acceptance standards are not included in ASME Section Xl, acceptance

standards will be developed using appropriate analytical techniques (i.e., elastic-plastic fracture

mechanics). As an option, the applicant will use the latest ASME Code methodology, as

accepted pursuant to 10 CFR 50.55a.

The applicant stated that additional inspections of nickel-based alloy locations required in

response to regulatory correspondence (i.e., NRC bulletins and GLs) or to industry initiatives'-

(i.e., MRP) during the current term of operation will carry forward into the period of extended

operation.

The staff concludes that based on the response to RAI B.1.1.2-3, the applicant will implement

the appropriate changes (i.e., those that assure the structural integrity of the RVHs and other

Alloy 600.components in the' primary coolant system during the extended period of operation);

therefore, the staff considers RAI B.1.1.2-3 closed.

Corrective Actions The applicant stated that component repair and replacement procedures

are in accordance with ASME Code, Section Xl,rrequirements, and it will implement corrective'

actions in accordance with the CNP Corrective Action Program. The applicant implements the

CNP quality assurance procedures, review and approval processes, and administrative controls

in accordance with the requirements of Appendix B to-10 CFR Part 50. The applicant stated

that the CNP corrective actions are consistent with the GALL Report. This element is

acceptable to the staff because it is in accordance with the requirements of Appendix'B to

10 CFR Part 50 and is consistent with the GALL Report.

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Confirmation Process The applicant stated that the CNP Corrective Action Program addresses

confirmation processes to ensure that preventive actions and appropriate corrective actions are

adequate. The applicant stated that it implements the CNP quality assurance procedures, review and approval processes, and administrative controls in accordance with the

requirements of Appendix B to 10 CFR Part 50. The applicant stated that the CNP confirmation

process is consistent with the GALL Report. This element is acceptable to the staff because it

is in accordance with the requirements of Appendix B to 10 CFR Part 50 and is consistent with

the GALL Report.

Administrative Controls The applicant stated that it implements the CNP quality assurance

procedures, review and approval processes, and administrative controls in accordance with the

requirements of Appendix B to 10 CFR Part 50. The applicant performs administrative control

for both safety related and nonsafety related SCs according to the existing Document Control

Program in accordance with the Quality Assurance Program description (QAPD). The applicant stated that the CNP administrative controls are consistent with the GALL Report. This element

is acceptable to the staff because it is in accordance with the requirements of Appendix B to

10 CFR Part 50 and is consistent with the GALL Report.

Operatina Experience The applicant stated that the Alloy 600 Aging Management Program is a

new program for which there is no CNP-specific operating experience. The applicant will

consider industry and plant-specific experience in the development of this program as

appropriate.

UFSAR Supplement

In Section A.2.1.1 of Appendix A to the LRA, the applicant provided its UFSAR Supplement for

the Alloy 600 Aging Management Program. The staff reviewed the UFSAR Supplement and

finds that the summary description contains a sufficient level of information to satisfy 10 CFR 54.21(d); therefore, it is acceptable.

Conclusion

On the basis of its review of the applicant's program, the staff concludes that the applicant has

demonstrated that it will adequately manage the effects of aging so that the intended functions

of SCs will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

The staff has reviewed the information provided in Section B.1.1 of Appendix B to the LRA, as

supplemented by the applicant's responses to the RAIs in its letters dated August 11, 2004. On

the basis of this review, the applicant demonstrated that it will have a program in place, approved by the staff, which demonstrates that it will adequately manage the effects of aging associated with Alloy 600 Class 1 components so that there is reasonable assurance that the

intended functions will by maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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3.0.3.3.2 Bolting and Torquing Activities

Summary of Technical Information in the ApDlication

Section B.1.2, "Bolting and Torquing Activities," of the LRA discusses the applicant's Bolting

and Torquing Activities Program. The applicant stated that this program is an existing plantspecific program. The GALL Report has no comparable program. The NRC previously

evaluated and approved a similar program in NUREG-1743, "Safety Evaluation Report Related

to the License Renewal of Arkansas Nuclear Power Plant, Unit 1," issued April 2001.

Furthermore, the Bolting and Torquing Activities Program relies on industry recommendations

as delineated in EPRI guidelines for a comprehensive bolting integrity program.

The program covers bolting in high-temperature systems and in applications subject to

significant vibration, -as identified in the AMR. Preventive actions include the proper selection of

bolting material and the use of the appropriate lubricants and sealants in accordance with EPRI

guidelines.

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. Gaskets, gasket seating surfaces, and fasteners are inspected for damage that

would prevent proper sealing.

The applicant stated that the Bolting and Torquing Activities Program is a preventive program.

Actions performed under the program prevent the aging effect of loss of mechanical closure

integrity. This program is credited with managing the loss of mechanical closure integrity for

bolted connections and bolted closures. According to the applicant, the CNP site procedures

provide the acceptance criteria, and the LRA does not discuss them: The applicant stated that

repair and replacement are in conformance with EPRI guidelines, and it will implement specific

corrective actions in accordance with the CNP Corrective Action Program.

The applicant reviewed operating experience relative to CNP bolting and torquing activities,

including CRs,- LERs, and NRC inspection reports. The review revealed limited problems with

bolting and torquing activities. The applicant has and will continue to factor operating

experience, both at CNP and in the nuclear industry, into program improvements.

In conclusion, the applicant stated the following:

The Bolting and Torquing Activities Program effectively manages aging effects.:

Continued implementation of this program provides reasonable assurance that the aging

effects associated with bolted closures will be managed such that applicable structures

and components will perform their intended functions consistent with the current

licensing basis for the period of extended operation.- -

Staff Evaluation

The applicant credited CNP AMP B.1.2, "Bolting and Torquing Activities," an existing plantspecific program,;with managing the loss of mechanical closure integrity.. The program covers

bolting in high-temperature systems and in applications subject to significant vibration. The

staff notes that the GALL Report credits GALL AMP XI.M.1 8, "Bolting Integrity," for-monitoring

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the loss of material, cracking, and the loss of preload. In addition, accepted bolting integrity

programs (such as EPRI 104213) recommend monitoring for loss of preload as one of the

parameters monitored or inspected. Monitoring for cracking of high-strength bolts (actual yield

strength equal or greater than 150 ksi) is also recommended.

RAI B.1.2-1

Based on the above, the staff asked the applicant in RAI B.1.2-1 to provide the following

information:

(A) Identify the areas of the Bolting Integrity Program at CNP which are consistent with GALL

AMP XI.M18, as well as those aspects in which it is different.

(B) Discuss how the CNP Bolting and Torquing Activities Program would manage the loss of

preload aging effect.

(C) Discuss the inspections associated with the Bolting and Torquing Activities Program at

CNP which may be beyond the requirements of ASME Code, Section Xl.

(D) Identify any high-strength bolts included within the boundary of the ESFs, auxiliary, or

steam and power conversion systems.

(E) Because the LRA does not identify the loss of preload as an AERM for bolts in the CNP

auxiliary system, explain how this aging effect would be managed in this system.

(F) Discuss how the consideration of SCC as an applicable aging effect took into account the

factors that can cause SCC in stainless steel bolts, such as stainless steel grade, method

of hardening (i.e., strain, precipitation or age hardening) environment, and stress levels.

In its response, the applicant stated the following:

(A) The Bolting and Torquing Activities Program is an existing plant-specific

program that was not compared to the NUREG-1 801, Section Xl.M1 8, Bolting Integrity Program. The program described in NUREG-1 801, Section XI.M1 8,

covers all bolting within the scope of licensee 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 (see response to

paragraph (f) below). Loss of material is managed by other programs

identified in LRA Appendix B, as indicated in the LRA Section 3 aging

management review results tables. Thus, the plant-specific. Bolting and

Torquing Activities Program, which is used only to prevent loss of mechanical

closure integrity, is not comparable to NUREG-1 801, Section XI.M1 8.

In LRA Section B.1.2, the ten attributes of the Bolting and Torquing Activities

Program were provided to allow for assessment of this program, independent

of NUREG-1801, Section XI.M18.

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(B) The Bolting and Torqiuing Activities Program manages loss of preload by

assuring that proper torque values are applied to bolted closures. With proper

design of bolted closures, selection of appropriate torque values prevents loss

of preload due to vibration or thermal cycles. -

(C) The Bolting and Torquing Activities Program is a preventive program. The

associated inspections are a check of the bolt torque performed after joint

assembly and verification of proper gasket compression after torquing.

(D) CNP piping material specifications do not permit, nor have they historically

permitted, high-strength bolting in non-Class 1 systems. Review of operating

experience did not identify problems with cracking of high strength bolting in air

environments. - -- ; - - -

(E) 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. As discussed in paragraph (b), above, the Bolting and Torquing

Activities Program manages loss of preload by assuring that proper torque

* -values are applied to bolted closures. With proper design of -bolted closures;

selection of appropriate torque values prevents loss of preload due to vibration

or thermal cycles. The Bolting and Torquing Activities Program implements.

this approach to manage loss of mechanical closure integrity due to loss of

preload for the mechanical systems presented in LRA Tables 3.2.2-2, 3.3.2-7-

3.3.2-8, 3.3.2-9, 3.3.2-11, and 3.4.2-1 through 3.4.2-4.

(F) Stress corrosion cracking (SCC) occurs through the combination of high stress

(both applied and residual tensile stresses), a corrosive environment, and a

susceptible material. Proper lubricants and sealant compounds are used to

minimize the potential for SCC. The Bolting and Torquing Activities Program

specifies appropriate lubricants and sealants to preclude introduction of

significant contaminants.

The AMRs assumed the presence of sufficient stress to initiate SCC if stainless steel bolting

were subject to a corrosive environment. However, SCC very rarely occurs in austenitic

stainless steels below 60 0C (140 OF). In the instances where SCC is observed in stagnant,-.

oxygenated, borated water below 60 0C (140 OF), the presence of a significant contaminant.

(halogens, specifically chlorides) is identified to be affecting the failed components. Since

stainless steel bolted closures are exposed to ambient temperature rather than

high-temperature process fluids, cracking of non-Class 1 stainless steel bolting is not an AERM.

The applicant limited its discussion of cracking to SCC. The GALL Report (in Section VIII

H.2-b) also discusses cracking in closure bolting in high-pressure or high-temperature systems

caused by cyclic loading. Therefore, the discussion should also include the potential for

cracking caused by cyclic loading.

The applicant stated that the Bolting and Torquing Activities Program assures that proper

torque values are applied to bolted closures such that the loss of mechanical closure integrity

as a result of loss of preload due to high temperature does not occur. GALL AMP XI.M18

encompasses all safety related bolting. The CNP Bolting and Torquing Activities Program is

3-85
limited to only high temperature bolting and applications subject to significant vibration. Other

CNP programs address different aspects of GALL AMP XI.M18. For example, the CNP

Inservice Inspection Program for Class 1, 2, and 3 bolted closures includes the ASME Code,

Section Xl, requirements. In addition, the Boric Acid Corrosion Prevention and System Walkdown Programs include periodic inspections of pressure-retaining components (including the closure bolting) for signs of leakage that may be caused by loss of preload, cracking, or the

loss of material. The applicant has clarified that loss of preload is prevented in other safety related bolting as a result of its maintenance practices. The staff finds the applicants response reasonable and acceptable because its maintenance practices are comprehensive to assure

the prevention of the loss of preload and the potential for cracking caused by cyclic loading.

Scope of Program The applicant stated that the Bolting and Torquing Activities Program covers

bolting in high-temperature systems and in applications subject to significant vibration, as

identified in the AMRs. The applicant did not identify the applicable AMPs that are credited with

managing age-related degradation of bolting or threaded fasteners.

RAI B. 1.2.2-1

In RAI B.1.2.2-1, the staff asked the applicant to identify the AMPs that are credited with

managing age-related degradation of bolting and/or threaded fasteners and identify the material

and the systems where they are present.

In its response, the applicant stated the following:

Aging management reviews of the following systems credit the Bolting and Torquing Activities Program with managing loss of mechanical closure integrity for carbon and

stainless steel bolting:

Exposed to High Temperatures or Vibration from Diesel Engines

System LRA Section

Fire protection (fire pump diesel engines) 3.3.2.1.7

Emergency diesel engine 3.3.2.1.8

Security diesel engine 3.3.2.1.9

LRA Table

3.3.2-7

3.3.2-8

3.3.2-9

Exposed to High Temperatures

System

Containment isolation

Miscellaneous systems in scope for

10 CFR 54.4(a)(2)

Main feedwater

Main steam

Auxiliary feedwater

Steam generator blowdown

LRA Section

3.2.2.1.2

3.3.2.1.11

LRA Table

3.2.2-2

3.3.2-11

3.4.2.1.1

3.4.2.1.2

3.4.2.1.3

3.4.2.1.4

3.4.2-1

3.4.2-2

3.4.2-3

3.4.2-4

The RCS AMR credits the Bolting and Torquing Activities Program, in conjunction with the

Inservice Inspection Program and the Boric Acid Corrosion Prevention Program, with managing loss of mechanical closure integrity for the following:

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* low-alloy steel (LAS) and stainless steel bolting for Class 1 valves and blind flanges, as

listed in LRA Table 3.1.2-3

* LAS bolting for reactor coolant pump main flange and pressurizer manway bolting' as listed

in LRA Table 3.1.2-3 and 3.1.2-4

* 'LAS 'and carbon steel bolting for steam generator components, as listed in LRA Table 3.1.2-

5

The applicant has clarified that all safety related bolting as addressed in GALL AMP is included

in its scope.

Preventive Actions The applicant stated that the program preventiv eactions include the prope'r

selection of bolting material and the use of appropriate lubricants and sealants, in accordance

with EPRI guidelines. The 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 controlled procedurally if the action is recommended by a vendor 6r if it is determined that

hot torque is necessary on a case-by-case basis. -

RAI B. 1.2.2-2

The preventive actions did not clearly indicate which EPRI guidelines the applicantrwould use to

select the proper bolting'material, lubricants, and sealants. The applicant did not identify the

actions and materials that it would use for replacement to demonstrate acceptable - :

management of ARDMs.

Therefore, in RAI B.1.2.2-2, the staff asked the applicant to identify the EPRI guidelines to be

used for selection of bolting material, lubricants, and sealants, iri6luding specific actions and

material replacements, to-demonstrate acceptable management of ARDMs. The applicant was

also asked to provide an example of a case that would require a hot torque check of a bolted

closure.

In its response, the applicant stated the following:

The EPRI guidelines used are NP-5067, Good Bolting Practices, and

TR-104213, Bolted Joint Maintenance & Applications Guide.

Fastener material replacements are performed in accordance with piping

specifications or approved configuration changes. Piping specifications require

that boric acid corrosion resistant fastener material be-used for bolted joints on

systems containing borated water. Also, low yield strength bolting and low

chloride'and sulfur content threaded fastener lubricants are specified to minimize

the potential for SCC. --- : 

The site maintenance procedure for the feedwater stop check valves provides an

example of hot torque requirements'. The procedure requires re-torquing of the

bonnet cap screws at normal operating'temperattire'and pressure as a final postmaintenance condition, as recommended by the vendor'technical manual.-

3-87 -
The RAI response identifies appropriate EPRI references and also addresses the exceptions

identified in NUREG-1339, as referenced in GALL AMP XI.M18.

Parameters Monitored or Inspected. The applicant stated that torque values are monitored

when the bolted closure is assembled. Maintenance personnel visually inspect components

involving bolted closures to assess their general condition during maintenance. They inspect

gaskets, gasket seating surfaces, and fasteners for damage that would prevent proper sealing.

RAI B. 1.2.2-3

The staff found that this element did not provide adequate detail to assure that ARDMs are

managed. Since closure bolting is exposed to air, moisture, and leaking fluid (boric acid)

environments, it is subject to the loss of material and crack initiation and growth.

Therefore, in RAI B.1.2.2-3, the staff asked the applicant to (1) inspect the bolting closures

during maintenance, (2) confirm that the program inspections are integrated with the CNP

Inservice Inspection Program and the results are tracked within this program, (3) confirm that

the visual inspections are performed in accordance with ASME Code, Section Xl, and (4) justify

the exclusion of the loss of material and crack initiation and growth from this element.

In its response, the applicant stated the following:

The Bolting and Torquing Activities Program manages loss of mechanical

closure integrity due to loss of preload for closure bolting in high-temperature

systems and applications subject to significant vibration.

Loss of material is excluded from this program because other programs, such as

the Boric Acid Corrosion Prevention Program and the System Walkdown

Program, which are described in LRA Sections B.1.4 and B.1.38, respectively,

manage loss of material for closure bolting and loss of mechanical closure

integrity for closure bolting exposed to boric acid. Specific applications are

identified in LRA Section 3 aging management review results tables. Loss of

material (and ultimately loss of mechanical closure integrity) for 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.

Therefore, visual inspections for loss of material and loss of mechanical closure

integrity, as required by the Boric Acid Corrosion Prevention Program and

System Walkdown Program, are adequate to assure that the closure bolting can

perform its intended function.

Crack initiation and growth are excluded from this program because the

Inservice Inspection Program manages cracking of bolted closures in Class 1

systems. Both the Inservice Inspection-ASME Section Xl, Subsection IWB,

IWC, and IWD Program and the Inservice Inspection-ASME Section Xl,

Subsection IWE Program, which are described in LRA Sections B.1.14 and

B.1 .15, respectively, provide for ASME Section Xl inservice inspections of

Class 1 bolted closures. Specific applications are identified in LRA Section 3.1

aging management review results tables. Cracking is not an aging effect

requiring management for non-Class 1 bolting applications due to low operating

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temperatures compared to Class 1 bolting applications and the use of low yield

strength bolting and low chloride and sulfur content threaded fastener lubricants.

The applicant's response states that cracking is not an AERM for non-Class 1 bolting

applications because of the low operating temperatures and proper use of lubricants. The staff

finds the applicants response reasonable and acceptable because it clarifies the reason that

cracking caused by vibration and cyclical loading is not applicable to non-Class 1 systems.

Detection of Aging Effects The applicant stated that the Bolting and Torquing Activities

Program is a preventive program. Actions performed under the program prevent the aging

effect of loss of mechanical closure integrity. The applicant credited this program with

managing the loss of mechanical closure integrity for bolted connections and bolted closures.

RAI B. 1.2.2-4

The program is intended to manage the loss of mechanical closure integrity for bolted

connections and bolted closures. However, the applicant did not provide justification to support

the program's ability to accomplish this.

Therefore, in RAI B.1.2.2-4, the staff asked the applicant to provide justification, including

codes and standards referenced, that the technique and frequency used at CNP are adequate

to detect the aging effects before a loss of component function occurs.

In its response, the applicant stated the following:

The Bolting and Torquing Activities Program manages loss of mechanical

closure integrity due to loss of preload for closure bolting in high-temperature

systems and applications subject to significant vibration. Specific applications

are identified in the LRA Section 3 aging management review results tables. -

Program standards are EPRI NP-5067, Good Bolting Practices, and TR-104213,

Bolted Joint Maintenance & Applications Guide. These standards are used

throughout the industry and have proven effective in managing loss of preload

for closure bolting. Review of operating experience did not identify problems;

with loss of preload for bolted closures at CNP.

The applicant's response states that a review of operating experience did not identify problems

with loss of preload for bolted closures at CNP and that this is consistent with industry -

experience where such maintenance practices and other factors are similar.

Monitoring and Trending The applicant stated that torque values are monitored during the bolt

torquing process, and that trending is not applicable to this program.

RAI B. 1.2.2-5

The staff finds that the applicant did not provide adequate detail under this element to assure

that ARDMs are adequately managed. The applicant previously stated that maintenance

personnel perform visual inspections to assess the general conditions in the bolted closures.

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In RAI B.1.2.2-5, the staff asked the applicant to confirm that the program inspections are

integrated with the CNP Inservice Inspection Program and discuss the method for integrating

the results of these visual inspections. Further, the applicant should provide justification for not

trending the results of the visual inspections.

In its response, the applicant stated the following:

Under the Bolting and Torquing Activities Program, loss of mechanical closure

integrity is managed by proper torquing during assembly of the bolted closure.

This program is a preventive program, rather than an inspection program. Visual

inspections to manage the effects of aging are not included in this program. In

LRA Section B.1.2, program element Parameters Monitored or Inspected, the

phrase, "visually inspect components used in the bolted closures to assess their

general condition during maintenance," is a description of how bolting and

torquing activities are performed. Prior to assembly, the mating surfaces and

bolting components are inspected for manufacturing defects, nicks, dents, or

scratches. After assembly, the closure is inspected for uniformity of gasket

compression, proper thread engagement, and proper locking tab installation.

Torque values are the only parameters monitored because the aging effect being

managed is loss of mechanical closure integrity, or loss of preload, not loss of

material or cracking. As described in l&M's response to RAI B.1.2.2-3, loss of

material and cracking are managed by other programs such as the Boric Acid

Corrosion Prevention Program, System Walkdown Program, and Inservice

Inspection Program, where applicable. Thus, the Bolting and Torquing Activities

Program does not include inspection results to trend.

The staff finds the applicant's response reasonable and acceptable because the applicant has

confirmed that the program inspections are integrated with the CNP Inservice Inspection

Program and noted the method for integrating the results of these visual inspections. Further,

the applicant has provided justification for not trending the results of the visual inspections.

Acceptance Criteria The applicant stated that the CNP site procedures provide the acceptance

criteria, such as mating surfaces smooth and free of major defects, proper and adequate thread

engagement, and use of appropriate torque values.

The NRC staff found that the applicant's acceptance criteria were not definitive enough to

determine whether the applicant would allow pressure boundary leakage if the component could

perform its intended function.

RAI B. 1.2.2-6

In RAI B.1 .2.2-6, the staff asked the applicant to discuss how it will handle pressure boundary

leakage and the requirements it will use to determine when leakage is acceptable and when

repair or replacement is necessary.

3-90
In its response, the applicant stated the following:

As discussed in the Statements of Consideration for the Final Part 54 Rule, the

first principle of license renewal is that, with the exception of age-related

degradation unique to license renewal and possibly a few other issues related to

safety only during the period of extended operation of nuclear power plants, the

regulatory process is adequate to ensure that the licensing bases of all currently

operating plants provides and maintains an acceptable level of safety so that

operation will not be inimical to public health and safety or common defense and

security. Leakage is documented and evaluated through the Corrective Action'-

Program. The quantity of leakage deemed acceptable and the need for repair or

replacement is determined in accordance with requirements of the existing plant

processes and activities that are addressed by the existing regulatory process.

As a matter of conservative operating practice, administrative limits for which -

CNP would take action are established significantly below regulatory

requirements. -

The staff finds the applicant's response reasonable and acceptable because the applicant has

discussed how it handles pressure boundary leakage and the requirements it will use to

determine when leakage is acceptable and when repair or replacement is necessary.

Conclusion

On the basis of its review and inspection of the applicant's program, the staff finds that the,

program adequately addresses the 10 program elements defined in Branch Technical Position

(BTP) RLSB-1 -in Appendix A.1 to the SRP-LR, and that the program will adequately manage

the aging effects for which it is credited. The staff also reviewed the UFSAR Supplement for

this AMR and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

Therefore, on the basis of its review, the staff concludes that the applicant has demonstrated

that the Bolting and Torquing Activities Program will adequately manage the effects of aging so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.0.3.3.3 Boral Surveillance

Summary of Technical Information in the Application

Appendix B.1 .3, "Boral Surveillance," of the LRA presents the applicant's program to manage

aging of the Boral neutron absorber in the SFP. The applicant stated that this existing plantspecific program has no comparable GALL program. -This AMP is credited with managing the

aging of the boral in the storage racks by evaluating boral coupons. The coupons are

positioned to receive a higher radiation dose than the functional boral panels. The applicant

stated that measurements of certain physical and chemical properties of Boral coupons provide

an assessment of the stability and integrity of the boral in the storage cells.

According to the applicant, the most recent coupon testing indicated no significant changes in

coupon dimensions, weight, specific gravity, or Boron-1 0 areal density. Minor corrosion pitting

3-91 1
was observed, but it was considered insignificant. The applicant reviewed industry operating

experience concerning hydrogen gas generated by interaction of the fuel pool water with boral.

No changes at CNP were deemed necessary as a result of the industry experience.

Staff Evaluation

Scope of Program. The applicant stated that the Boral Surveillance Program includes the boral

in the CNP SFP. This element is acceptable to the staff because boral is used only in the SFP.

RAI B. 1.3-1

Preventive Actions. The applicant noted that the program is an inspection program and does

not include prevention measures. However, industry experience has found that venting of the

racks is a design feature that can help prevent a key aging effect (bulging). The staff,

therefore, asked in RAI B. 1.3-1 by letter dated May 19, 2004, that the applicant state whether

the wrappers in the storage racks are vented to allow the escape of corrosion-generated

hydrogen gas, or if any other measures are incorporated to prevent the wrappers from bulging.

In a letter dated August 11, 2004, the applicant responded that the storage racks at CNP are

vented. The staff considers this design feature to be helpful in preventing bulging of the

storage racks. Information Notice (IN) 83-29 describes fuel binding in 1982 at Maine Yankee

caused by fuel rack deformation. Drilling holes in the top of the plates reduced the deformation,

presumably by releasing corrosion-generated hydrogen.

Parameters Monitored or Inspected. The applicant listed the boral coupon parameters that

would be monitored or inspected as neutron attenuation, dimensions (length, width, thickness),

weight, and specific gravity. Since the program seeks to manage aging of boral panels by

monitoring coupons believed to accurately represent the panels, the staff asked the applicant,

in RAI B.1.3-1 by letter dated May 19, 2004, to discuss the relationship between the boral

coupon measurements and the integrity of the boral panels.

In a letter dated August 11, 2004, the applicant responded that the coupon tree is moved each

refueling outage to be surrounded by the highest power discharged fuel assemblies. The

applicant stated that the boral coupons degrade faster than the boral panels because the

coupons are exposed to a higher cumulative radiation dose, and the coupons therefore provide

a definitive indication of the acceptability of the boral panels in the storage racks. Since the

applicant should ensure that the boral coupons receive a higher radiation dose than the boral

panels, the staff agrees that monitoring the coupons should provide an early indication of

potential degradation of the boral panels in the storage racks.

In RAI B.1.3-1, the staff also asked the applicant to explain its use of the measured values of

coupon specific gravity to manage aging. The UFSAR Supplement (see page A-12 of the LRA)

and the Boral Surveillance Program (see page B-23 of the LRA) list specific gravity as one of

the parameters monitored. However, the applicant did not discuss specific gravity as part of the

acceptance criteria in the AMP. According to the applicant, specific gravity is one of the

physical parameters used to identify early indications of boral degradation. An unexplained

decrease in specific gravity could indicate loss of material and would result in an engineering

evaluation and possibly a change in the measurement schedule.

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The staff considers this program element acceptable because experience has shown that boral

degradation in the ,SFP environrriint occurs slowly and can be detebted in the early stages by

the methods proposed. The measurements of neutron attenuation, physical distortion, and

weight change would detect coupon degradation that would precede a loss of functionality inthe boral panels (neutron absorption and fuel assembly spacing). Moreover, unacceptable

coupon results would initiate an engineering evaluation and, if considered necessary, direct

testing of the storage racks (i.e. blackness testing).

.. , .. . . . . - . - - - - - . . . .,C: ..

Detection of Aging Effects. -The staff asked the applicant, in RAI B.1.3-1 by letter dated

May 19, 2004, to discuss the accuracy of the neutron attenuation and thickness measurements

that would be used to monitor the coupons, as well as the accuracy required to detect

degradation of the panels in the fuel racks. According to the acceptance criteria listed in the

LRA, the applicant must be able to detect a 5-percent decrease in Boron-1 0 content and a

10-percent increase in thickness. In a letter dated August 11, 2004, the applicant responded

that the required accuracy for the thickness measurement is ±0.005 inches, and the actual

measurement accuracy is +0.001 inches. In a letter dated January21, 2005, responding to

related RAI B.1.3-2, the licensee confirmed that the thickness and Boron-10 measurement

capabilities meet or exceed the program specifications.-- The applicant explained that neutron

attenuation is compared on a relative basis to a boral reference standard. The staff finds these

acceptable because the accuracy of the measurement techniques is compatible with the

acceptance criteria. -

Monitoring and Trending. The applicant stated that it would conduct trending analysis by -

comparing the periodic inspection measurements and analysis to previous results. In a public

meeting on September 1,2004, the.staff asked the applicant to confirm that the prescribed

schedule for coupon removal and evaluation would include the extended operating period. In

an e-mail dated September 27, 2004, the applicant responded that the program does continue

during the extended operating period. The applicant stated that the "Conclusion" section of the'

program confirms this with the phrase "continued implementation," which refers to the period of

extended operation. : -- :

A November 2004 AMP inspection raised a concern that the applicant may not be performing

trending of the coupon measurements, and that the applicant's measurement capabilities may

be inadequate for trending. In a letter dated January-12, 2005, the staff requested that the

applicant clarify its capability for evaluating coupon thickness, provide the results of past - -

coupon evaluations, and confirm that the 5-percent uncertainty in Boron-10 areal density is

within the uncertainty tolerance used in the most recent criticality safety analysis.- The staff also

asked the applicant to provide dates for removal and evaluation 'of coupons in the past, as well

as an explanation of how coupon removal and evaluation times are determined.' In a letter

dated January 21, 2005, the applicant responded that the calibrated measurement instruments

are capable of measuring length, width, and thickness to ± 0.04, 0.02, and 0.002 inches,-

respectively, all of which are smaller than the 10% acceptance criterion. The applicant also

stated that the limit of 5-percent Boron-1 0 areal density variation is conservative with respect to

the SFP criticality analysis. -The applicant uses the coupon size and Boron-10 area density

measurements to identify trends in degradation based on exposure time.

Regarding the schedule and past results, the applicant responded in the January 21, 2005 letterthat coupon removal and evaluation dates are based on vendor recommendations intended to

produce more radiation dose than the expected lifetime dose for normal storage. During the -

3-93
period of extended operation, the evaluation interval will be 5 years, which the applicant stated

is recommended by the Boral vendor and supported by the coupon results. The staff reviewed

results from coupons tested in 1994 and 2001 and confirmed that there were no significant

changes in coupon dimensions, weight, density, or Boron-1 0 areal density.

In the section of the LRA that discusses operating experience, the applicant stated that it noted

minor corrosion pitting during the most recent inspection. The staff asked the applicant, in RAI

B.1.3-1 by letter dated May 19, 2004, to describe this pitting and discuss the trending procedure

required to ensure that the pitting will not increase to affect the functionality of the boral. In a

letter dated August 1 1, 2004, the applicant responded that, after visual inspection, eight blisters

formed on the coupon surface during heating to remove residual moisture. The applicant

stated that the blisters resulted from localized damage to the aluminum cladding by mechanical

impacts during manufacturing or by corrosion pitting. Following penetration of the cladding,

moisture entered the core of the coupon at the location of the hole or pit. According to the

applicant, subsequent corrosion sealed the moisture in the core, and heating caused the

cladding to separate from the core and form a blister. Microscopy revealed a pit or small hole in

the cladding at each blister location. The applicant stated that this amount of corrosion pitting

would not affect the boral functionality. The applicant compares coupon test results with

baseline data and past test results to ensure that boral function is not adversely affected. The

applicant evaluates adverse conditions as part of the Corrective Action Program. The staff

finds this element acceptable because the applicant monitors parameters that would indicate

degradation and identifies trends in the parameters by comparison to baseline and interim test

results.

Acceptance Criteria On page B-24 of the LRA, the applicant identified the acceptance criteria

as a decrease of no more than 5 percent Boral-1 0 content, as determined by neutron

attenuation, and a maximum increase of 10 percent in thickness at any point over the initial

thickness at that location. The applicant identified additional parameters that are examined for

early indications of potential boral degradation and possibly a change in measurement

schedule, including visual or photographic evidence of surface deterioration (general or pitting

corrosion, edge deterioration), unaccountable weight loss, and areas of reduced boron density

in neutron radiographs.

In a public meeting on September 1, 2004, documented as follow-up item to RAI B.1.3-1 in a

letter dated September 29, 2004, the staff asked the applicant to provide the technical basis for

the acceptance criteria (5-percent maximum Boron-10 decrease and 10-percent maximum

thickness increase). The staff asked the applicant to provide a reference if the NRC previously

reviewed and approved the Boral Surveillance Program at CNP. In a letter dated

October 18, 2004, the applicant stated that the CNP Boral Surveillance Program had not

previously been reviewed and approved by the NRC, but similar programs had been approved

for two other plants. The applicant stated in the October 18, 2004, letter that it selected a 5-

percent decrease in Boron-10 areal density because this is the limit of precision in the

measurement and it is also within the usual uncertainty tolerance applied in the nuclear

criticality safety analyses. In a letter dated January 12, 2005, the staff requested that the

applicant confirm that the 5-percent variation in Boron-1 0 areal density was used in the most

recent criticality safety analysis for CNP. In a letter dated January 21, 2005, the applicant

responded that a 5-percent variation is conservative because the Boron-1 0 density assumed in

the most recent fuel pool criticality analysis (0.030 g/cm2) is 15-percent less than the nominal

Boron-10 density for the adsorber panels (0.0345 g/cm2).

3-94
With respect to the coupon thickness measurement, the applicant stated that a 10 percent

increase (0.0075 inches) in coupon thickness is sensitive enough to detect coupon swelling or

blistering before the boral panels could swell or blister enough to cause binding of fuel

assemblies. The applicant also noted that swelling or blistering does not affect the functionality

(reactivity control) of the boral. The staff finds these criteria acceptable because they measure

changes small enough to provide reasonable assurance that corrective actions could be taken

before a loss of functionality occurs.

Corrective Actions Section B.0.3 of the LRA discusses the corrective-actions, which are

common to all AMPs. The applicant stated that the corrective actions are consistent with the

GALL Report. The Boral Surveillance Program description provides additional information

about the corrective actions for that program. The applicant stated that, in addition to

implementing the CNP Corrective Action Program, the Boral Surveillance Program corrective

actions will include an investigation and engineering evaluation if the coupon acceptance

criteria are not met. Additional testing, such as blackness testing of the storage racks, may be

performed based on the engineering evaluation.

Confirmation Process and Administrative Controls Section B.0.3 of the LRA discusses these

elements,.which are common to all AMPs. The program description did not provide any

program-specific details.

Operating Experience The applicant stated that CRs resulted in the correction of procedural

problems, including insufficiently defined responsibilities in the controlling procedure leading to

missed samples, missing references to NRC commitments, and noncompliance with

administrative guidelines.

The applicant stated that the most recent testing of boral coupons detected no significant

changes in the measured parameters. The staff asked the applicant, in RAI B.1.3-1 by letter

dated May 19, 2004,-to justify this statement and describe the amount of change that was

found. In a letter dated August 11,2004, the applicant described the changes. The coupon

dimensions changed by about -0.67-percent to +1.19-percent, with the difference attributed tooxide thickness or surface and edge irregularities; the dry weight and density increased about

0.5-percent from the original values; and the small increase in Boral-1 0 areal density was within

the measurement precision.

Regarding the schedule and past results, the applicant responded in the January 21, 2005 letter

that two coupon evaluations had been missed and discovered in 1999, and that corrective

actions have since been implemented to ensure that future sampling opportunities will not be

missed. These corrective actions include upgrades to the work control process; and

improvements in process and program ownership.

Degradation of boral has occurred in the industry both in boral storage rack panels and boral

coupons. Bulging of the cover plates (wrappers) on boral panels was found to be a result of

hydrogen gas produced by corrosion of the boral. In the' LRA, the applicant stated that it did not

consider any program changes to be necessary as a result of industry experience with

hydrogen gas generation, but it did not provide any reasons. The staff therefore requested, in

RAI B.1.3-1 by letter dated May 19, 2004, that the applicant discuss the technical basis for

concluding that industry experience with hydrogen gas does not affect the Boral Surveillance

Program. In the same RAI, the staff asked the applicant to discuss the impact, if any, that

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degradation of boral at Seabrook Nuclear Station is considered to have on the Boral

Surveillance Program at CNP. In September 2003, an inspection of boral test coupons at

Seabrook revealed bulging and blistering of the aluminum cladding. In a letter dated August

11, 2004, the applicant responded that it documented industry operating experience with

hydrogen gas generation and evaluated it within the Corrective Action Program.

The applicant described an industry operating event in which the interaction of SFP water and

boral plates in a multipurpose canister formed hydrogen gas. Though the boral plates used in

the multipurpose canister had been prepassivated, a small amount of unpassivated material

remained after the prepassivation process. Passivation is the formation of a corrosion product

film that protects a metal or alloy from further corrosion. The unpassivated material interacted

with water to produce aluminum oxide and free hydrogen gas. The staff notes that the ventedr

design of the boral panels will help to prevent bulging of the panels by allowing corrosiongenerated hydrogen to escape. As discussed above with regard to Preventive Actions program

element, the deformation of boral panels at Maine Yankee was reduced by venting the panels

to release hydrogen.

The licensee also discussed a September 2003 operating event in which bulging and blistering

of the aluminum cladding was found on boral test coupons at Seabrook. The applicant

responded that the blisters observed on the Seabrook coupon were different than the blisters

associated with pitting on the CNP coupons. As discussed above with regard to Monitoring and

Trending program element, the blisters on the CNP coupons were attributed to the coupon

heating process, which removes residual moisture from the coupon. The Seabrook coupon

blisters were observed during visual inspection before heating and subsequent testing.

Seabrook filed a report pursuant to 10 CFR Part 21, "Reporting of Defects and

Noncompliance," on September 15, 2003 (2003-0022-00). The applicant stated that two

tracking actions remain within the CNP Corrective Action Program. The first action will ensure

that additional information on the 10 CFR Part 21 issue is received and evaluated for CNP. The

second action will ensure that consideration is given to the Seabrook experience when the

results of the next CNP boral coupon test are compared to previous results. The staff finds that

the operating experience at CNP and other plants reveals significant information about

managing the aging of boral storage racks and monitoring boral coupons, and that the applicant

is applying this information in a way that will identify potential concerns with the functionality of

the boral.

The staff finds this element of the program acceptable because the applicant has implemented.

corrective actions to ensure that future sampling opportunities are not missed. In addition, the

applicant will examine and monitor CNP and industry experience (such as the Seabrook

incident) in order to maintain or enhance the effectiveness of the Boral Surveillance Program.

Therefore, the staff finds this program element acceptable.

UFSAR Supplement

The applicant provided the UFSAR Supplement for the Boral Surveillance Program in Section

A.2.1.3 of Appendix A to the LRA. The staff reviewed this section and accepts it as an

adequate summary of the program activities.

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Conclusion

Based on its review of the applicant's Boral Surveillance Program, the staff finds that the

program adequately addresses the 10 program elements defined in BTP RLSB-1 in Appendix

A.1 to the SRP-LR, and that the program will adequately manage the aging effects for which it

is credited. 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).

Therefore, based on its review, the staff finds that the applicant has demonstrated that the

Boral Surveillance Program will adequately manage the effects of aging so that the intended

functions of SCs will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.0.3.3.4 Bottom-Mounted Instrumentation Thimble Tube Inspection

Summary of Technical Information in the Application

Section B.1.5, "Bottom-Mounted Instrumentation Thimble Tube Inspection," of the LRA

discusses the applicant's Bottom-Mounted Instrumentation Thimble Tube Inspection Program.

The GALL Report does not have a corresponding program. The staff's technical evaluation,

below, describes the program.

Staff Evaluation

In LRA Section B.1.5, the applicant described its AMP to manage the integrity of the BMI

thimble tubes, which serve as a portion of the RCPB. As discussed in NRC Bulletin 88-09,

"Thimble Tube Thinning in Westinghouse Reactors," dated July 26, 1988, thimble tube wall

thinning can occur as a result of flow-induced vibration (FIV). This wear damage is detected at

locations associated with geometric discontinuities or area changes along the reactor coolant

flowpath, such as areas near the lower core plate, the core support forging, the lower tie plate,

and the vessel penetrations. The applicant developed its Bottom-Mounted Instrumentation

Thimble Tubes Inspection Program based on the guidance in Bulletin 88-09 to inspect for wear

damage.

The applicant designed its Bottom-Mounted Instrumentation Thimble Tube Inspection Program

for the detection of wear, not SCC. However, LRA Table 3.1.2-1 lists cracking as an AERM for

BMI thimble tubes and bullet plugs. Because of this inconsistency, the staff requested that the

applicant confirm that cracking for BMI thimble tubes is a credible degradation mechanism

requiring aging management and, if necessary, revise the program to include inspection for

cracking due to SCC. The staff addressed this issue in RAI B.1.5-1. Section 3.1.2.3.1 of this

SER provides the resolution of RAI B.1.5-1 as part of the AMR review.

The GALL Report does not evaluate this AMP. Therefore, the staff reviewed this AMP against

the 10 program elements using the guidance in BTP RLSB-1 in Appendix A to the SRP-LR.- -

The staff also reviewed the UFSAR Supplement to determine whether it adequately describes

the program.

Scope of Program. The applicant stated that all thimble tubes are within the scope of this

inspection program. The staff finds the scope of the program to be adequate because all

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thimble tubes are within scope and the applicant inspects the entire tube for wear resulting from

FIV.

Preventive Actions. As noted below with regard to the Operating Experience element, the

replacement of all thimble tubes with tubes with chrome plating at the wear areas constitutes a

preventive action. However, the service time of approximately 4 years is not long enough to

demonstrate the effectiveness of using chrome plating to mitigate the wear from FIV. RAI

B.1.5-3, generated with regard to the Monitoring and Trending and Acceptance Criteria

elements described below, reflects this concern.

Parameters Monitored or Inspected. The applicant will use eddy current examinations to

determine the wall thickness of the thimble tubes, allowing an assessment of the wear and wear

rate of each tube. The staff finds this acceptable because the eddy current examination has

been successfully used to determine wall thickness and wear rate.

Detection of Aging Effects. The LRA states that thimble tube eddy current inspections are

scheduled to be performed every third refueling outage. The applicant must provide the basis

for this schedule using industry and plant-specific data. RAI B.1.5-3, generated with regard to

the Monitoring and Trending and Acceptance Criteria elements described below, reflects this

concern.

RAI B. 1.5-2

Monitoring and Trending and Acceptance Criteria. The replacement, repositioning, or isolation

of BMI tubes is based on plant-specific calculations using the generic wear rate in

WCAP-1 2866, "Bottom Mounted Instrumentation Flux Thimble Wear." The acceptance criteria

are also derived from the WCAP report and require (1) replacement or isolation of a thimble

tube with 80 percent through-wall wear, (2) repositioning of a thimble tube with more than 40-

percent through-wall wear, provided that it is projected to remain under 80-percent until the next

inspection, and (3) replacement, isolation, or repositioning of a thimble tube with more than 40-

percent through-wall wear if it is projected to exceed 80-percent by the next inspection. Using

repositioning as an option for Criterion 3 for a tube which is projected to exceed 80-percent

wear by the next inspection is appropriate if the tube wear rates at all thimble tube locations are

established using plant-specific data collected during the past and are to be collected in future

inspections for the chrome-plated thimble tubes. The staff addressed this concern in RAI B.1.5-

2. The applicant made a final response to RAI B.1.5-2 in its letter dated October 18, 2004, that

the acceptance criteria are based on WCAP-12866 and that the final relocation position of a

thimble tube predicted to exceed 80-percent wear will be determined via the corrective action

evaluation of the eddy current results. The response to RAI B.1.5-2 further clarifies that

plant-specific wear data will be used to establish the tube wear rates for selecting candidate

repositioning location(s) to ensure that the repositioned tube wear will not exceed 80-percent by

the next inspection. Therefore, the staff considers RAI B.1.5-2 resolved.

RAI B. 1.5-3

Although WCAP-12866 has not been formally approved by the NRC, the NRC staff finds the

WCAP's 80-percent through-wall acceptance criteria to be acceptable because the remaining

20-percent will provide adequate structural integrity until the tube is capped or replaced. The

staff further determines that the CNP acceptance criteria are acceptable because the applicant

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proposed to take action when wear exceeds only 40-percent through-wall. This is adequate

considering the plant-specific operating experience of CNP during the past 10 years. In regard

to the frequency of inspection for thimble tubes, the applicant's proposed thimble tube

inspection every third outage is acceptable because no wear has been discovered in the past

three refueling outages for all thimbles. When wear appears, the inspection interval must be

reevaluated based on the observed thimble tube-specific wear rates. The applicant must

provide a revised inspection schedule, anticipating wear and based on the severity of wear.

The staff addressed this concern in RAI B.1.5-3.

In its response letter dated August 19, 2004, the applicant provided its BMI thimble tube

inspection history. This information reveals that thimble tube inspections were performed every

refueling outage until 1992 when 15 tubes were replaced for Unit 1 and 22 for Unit 2 with

selectively chrome-plated thimble tubes. In addition, an inspection conducted in January 1998

after three cycles of operation showed no indications of wear. Hence, the applicant completed

its plan of replacing all remaining thimble tubes with chrome-plated tubes in 2000. Again, an

inspection conducted in 2002 after one cycle of operation showed no indications of wear. -This

experience provides the basis for the applicant's proposed thimble tube inspection every third

outage.

Although the proposed inspection frequency is adequate for the next inspection, it may not be

adequate for all future inspections. As a follow-up to RAI B.1.5-3, the staff questioned the

applicant about the plant-specific wear rate and the severity of wear after wear appears in

thimble tubes and about the need to reevaluate the inspection interval accordingly. In its

response to this concern, the applicant states the following:

...[s]hould inspection results indicate that more frequent inspections are needed -

during the current term of operation or the period of extended operation, the ECT

frequency will be revised in accordance with the Corrective Action Program.

The staff finds this appropriate because stating that the ECT frequency will be revised in - -

accordance with the Corrective Action Program considering inspection results is equivalent to

revising the inspection schedule according to inspection results. In addition, the applicant

proposed to add the following sentence to the UFSAR Supplement for this AMP to clarify the

proposed inspection frequency:

[t]he inspection frequency is based on measured data and projected wear

results.

The staff considers this description adequate. Therefore, the staff's concern in RAI B.1.5-3 is

closed.

Operating Experience. The NRC documents thimble tube wear in Westinghouse reactors in IN

87-44, "Thimble Tube Thinning in Westinghouse Reactors," and NRC Bulletin 88-09. In

response to these notifications, CNP performed an eddy current examination of thimble tubes

every one or two outages until 2000 when it replaced all thimble tubes with tubes that are plated

with chrome in the areas subject to wear. Based on successful operating experience with the

chrome-plated tubes, the applicant revised the thimble tube eddy current inspection frequency

to once every third refueling outage. The staff determined that 4 years of operating experience

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are insufficient to conclude that the new tubes are free from wear. The staff addressed this

concern in RAI B.1.5-3, discussed above.

UFSAR Supplement

The staff also reviewed the UFSAR Supplement for this AMP, including the enhancement

discussed with regard to the Monitoring and Trending and Acceptance Criteria elements, and

finds that it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion

On the basis of its review of the applicant's program, the staff finds that the applicant has

addressed appropriately the attributes common to all GALL programs. The staff concludes that

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

Therefore, the staff concludes that actions have been identified and have been, or will be, taken

to manage the effects of aging during the period of extended operation on the functionality of

SCs subject to an AMR such that the activities authorized by a renewed license will continue to

be conducted in accordance with the CLB, as required by 10 CFR 54.29(a).

3.0.3.3.5 Heat Exchanger Monitoring

Summary of Technical Information in the Application

Section B.1.13, 'Heat Exchanger Monitoring," of the LRA describes the applicant's Heat

Exchanger Monitoring Program. In the LRA, the applicant committed that it will initiate the

plant-specific program before the period of extended operation. This is Commitment #9 in

Appendix A of this SER. The GALL Report has no comparable program. The applicant credited this program with inspecting heat exchangers for age-related degradation. If

degradation is found, then the applicant will evaluate its effects on the heat exchanger's design functions, including seismic operability.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section

B.1.13 of Appendix B to the LRA, regarding the applicant's demonstration of the Heat

Exchanger Monitoring Program, to ensure that it will adequately manage the effects of aging,

as discussed above, so that the intended functions of SCs 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

Table A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's management of aging effects through the effective incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated in

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Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scope of Program. The applicant stated, in Section B.1.1 3 of Appendix B to the LRA, that this

program manages aging effects on heat exchangers in the containment spray, emergency core

cooling, CEQ, CCW, EDG, ESF ventilation, control room ventilation, chemical and volume

control, and auxiliary feedwater (AFW) systems.

The staff confirmed that Section 3 of the LRA identifies the component type and systems for

which the Heat Exchanger Monitoring Program manages aging effects, which satisfies the

criteria defined in Appendix A.1 to the SRP-LR. On this basis, the staff finds that the applicant's

proposed scope is acceptable.

Preventive Actions. The applicant stated, in Section B.1.13 of Appendix B to the LRA, that for.

this program element the Heat Exchanger Monitoring Program is a monitoring program, and the

program will involve no actions to prevent or mitigate aging 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, in Section B.1.13 of Appendix B to

the LRA, that it will perform NDE. It may use eddy current testing to identify wall thinning and

cracking in shell-and-tube heat exchangers where practical. Heat exchanger heads, covers,

and tubesheets will be inspected using visual inspection methods where accessible. Where

monitoring is impractical, the applicant will evaluate replacement.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The Heat Exchanger Monitoring Program is acceptable because the NDE 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 program element is

acceptable.

Detection of Aging Effects The applicant stated, in Section B.1.13 of Appendix B to the LRA,

that this program manages the aging effects of loss of material and cracking for the tubes. An

appropriate sample population of heat exchangers will be determined based on operating

experience before 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. The eddy current inspection of

the tubes will occur 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. Where inspection is

impractical, replacement will be considered. Finally, inspection can reveal cracking and loss of

material that could result in degradation in the seismic qualification of the heat exchangers.

This program does not address fouling.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The applicant will (1) develop testing techniques based on industry operating

experience, (2) determine the sample population of heat exchangers based on operating

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experience before the inspections, and (3) perform an eddy current inspection of the tubes

every 10 years, or more frequently if inspection results indicate a need for more frequent inspections. On this basis, the staff finds that the Detection of Aging Effects program element

is acceptable.

Monitorina and Trending. The applicant stated, in Section B.1.13 of Appendix B to the LRA, that it will evaluate the results against established acceptance criteria and make an assessment

regarding the applicable degradation mechanism, degradation growth rate, and the allowable

degradation level. It will use this information to develop the future inspection scope and

inspection intervals.

The staff confirms that this program element satisfies the criteria defined in Appendix A.1 to the SRP-LR. The applicant will trend the inspection results, thereby enhancing its ability to detect

aging effects before a loss of intended function occurs. On this basis, the staff finds that the

Monitoring and Trending program element is acceptable.

Acceptance Criteria. The applicant stated, in Section B.1.13 of Appendix B to the LRA, that it

will establish the tube plugging limit for each heat exchanger to undergo eddy current inspection 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. In addition, the acceptance criteria for visual inspections of heat exchanger heads,

covers, and tubesheets will require no evidence of degradation that could lead to the loss of

function. If degradation that could lead to the loss of intended function is detected, the

applicant will write a CR and resolve the issue in accordance with the site Corrective Action

Program.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The applicant will find any degradation that is identified from visual inspections and could lead to the loss of intended function to be unacceptable and implement corrective

measures using the Corrective Action Program. On this basis, the staff finds that the

Acceptance Criteria program element is acceptable.

Operating Experience The applicant stated, in Section B.1.13 of Appendix B to the LRA, that

the Heat Exchanger Monitoring Program is a new program for which there is no operating experience. Eddy current inspections and heat exchanger internal visual inspections are

standard industry methods to manage aging effects in heat exchangers. These methods are

consistent with NRC-accepted industry practices. The applicant will consider industry and

plant-specific operating experience in the development of this program, as appropriate.

The staff reviewed the records associated with implementation of GL 89-13 to confirm that the

applicant is collecting plant-specific data on heat exchangers, including the results of

nondestructive evaluations, and using them in an appropriate manner.

The staff recognizes that the Corrective Action Program, which captures internal and external

plant operating experience issues, will provide reasonable assurance that operating experience is reviewed and incorporated in the future to provide objective evidence to support the

conclusion that the effects of aging are adequately managed.

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On the basis of its review and discussions with the applicant's technical staff, the staff

concludes that Heat Exchanger Monitoring Program will adequately manage the aging effects

that have been observed at the applicant's plant.

UFSAR Sunplement

In Section A.2.1.16 of Appendix A to 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 exposed to treated water in various

systems. The program will inspect heat exchangers for degradation using NDE,- such as eddy -

current inspections and visual inspections. If degradation is found, then the applicant will

perform an evaluation to determine its effects on the heat exchanger's design functions. The

applicant stated in Appendix A that it will initiate the Heat Exchanger Monitoring Program before

the period of extended operation.

The staff reviewed 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 the applicant,

has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs 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 Inservice Inspection-ASME Section Xl, Augmented Inspections

Summary of Technical Information in the Application

Section 6.1.18, "Inservice Inspection-ASME Section XI, Augmented Inspections," of the LRA

describes the applicant's Inservice Inspection-ASME Section XI, Augmented Inspection

Program. In the LRA, the applicant stated that it will initiate this plant-specific program before

the period of extended operation. The Gall Report has no comparable program. The applicant

credited this program with managing the effects of aging on selected components that are

outside the jurisdiction of ASME Code, Section XI. The existing program is used for other

components that do not require aging management in accordance with 10 CFR Part 54.

Augmented inspections are consistent; to the extent practical, with the appropriate ASME Code,

Section XI requirements, specifically regarding (1) selection of inspection methods, (2)

inspection frequency,-(3) percentage of components examined within a population, and (4)

acceptance criteria.

The applicant stated that it has implemented the applicable requirements of the 1989 edition of -

ASME Code, Section XI, approved NRC alternatives and relief requests, and other -

requirements specified in 10 CFR 50.55a for the third ISI interval. -

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Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section

B.1.18 of Appendix B to the LRA regarding the applicant's demonstration of the Inservice

Inspection-ASME Section XI, Augmented Inspection Program to ensure that it will adequately

manage the effects of aging, as discussed above, so that the intended functions of SCs will be

maintained consistent with the CLB throughout the period of extended operation.

The staff reviewed the Inservice Inspection-ASME Section Xl, Augmented Inspection Program

against the AMP elements found in Table A.1-1 and Section A.1.2.3 of Appendix A to the SRPLR and focused on the program's management of aging effects through the effective

incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated in

Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scope of Program. The applicant stated, in Section B.1.18 of Appendix B to the LRA, that the

Inservice Inspection-ASME Section Xl, Augmented Inspection Program scope includes

existing augmented inspections on selected components that are outside the jurisdiction of

ASME Code, Section Xl, and nondestructive inspections that will be implemented before the

period of extended operation to manage aging effects on portions of the containment spray

system.

The applicant stated that it will enhance the scope of this program to include volumetric

inspections of the spray additive tanks, the portions of the containment spray system that are

wetted by sodium hydroxide (i.e., piping up to the first normally closed valve), and the portion of

the discharge header in containment that may contain untreated water with concentrated

contaminants.

By letter dated October 31, 2003, the applicant committed to the enhancements applicable to

the Inservice Inspection-ASME Section Xl, Augmented Inspection Program and the

associated implementation dates. This is Commitment #10 of this SER.

The staff confirmed that the Scope of Program element satisfies the criteria defined in Appendix

A.1 to the SRP-LR. The proposed scope identifies the specific components for which the

program manages aging. On this basis, staff finds that the applicant's proposed program

scope is acceptable.

Preventive'Actions. The applicant stated, in Appendix B, Section B.1.18, to the LRA, that the

Inservice Inspection-ASME Section Xl, Augmented Inspection Program is a monitoring

program and will involve no actions to prevent or mitigate aging degradation.

The staff confirmed that the Preventive Actions program element satisfies the criteria defined in

Appendix A.1 to the SRP-LR. The staff did not identify the need for preventive actions for the

Inservice Inspection-ASME Section Xl; Augmented Inspection Program because it is a

condition monitoring program.

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Parameters Monitored or Inspected. The applicant stated, in Sebtion B.1.18 of Appendix B to

the LRA, that the program uses nondestructive inspections to monitor for cracking and the loss

of material (wall thinning).

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

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

program element is acceptable.

Detection of Aging Effects. The applicant stated, in Section B.1.18 of Appendix B to the LRA,

that it uses nondestructive inspections, such as volumetric'examination methods for ASME

Code, Section Xl, inspections of Class 1, 2, and 3 components. The ISI long-term plan' '

specifies the frequency of inspections. The applicant stated that it will enhance the'program to

include inspections to manage (1) the loss of material and cracking of the spray additive tanks

and the portions of the containment spray system that are wetted by sodium hydroxide (i.e.,

piping up to the first normally closed valve) and (2) the loss of material and cracking of the

portions of the discharge header in containment that may contain untreated water with

concentrated contaminants.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The program treats the in-scope spray additive tanks as Class 2 vessels and the

in-scope containment spray piping components as Class 2 piping, in accordance with ASME

Code, Section Xl. Inspections associated with this AMP 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 that the Detection of Aging Effects program element is

acceptable.

Monitoring and Trending. The applicant stated, in Section B.1.1 8 of Appendix B'to the LRA,

that it will implement the new inspections before the period of extended operation. This

program does not perform trending. However, the Corrective Action Program applies to this

program. This provides reasonable assurance that the applicant will identify trends entailing

repeat failures to meet acceptance criteria and address them with appropriate corrective

actions.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. Because of the slow-acting nature of aging mechanisms causing these aging '

effects, the frequencies specified in ASME Code, Section Xl, will be adequate to manage the

effects of aging. On this basis, the staff finds that the Monitoring and Trending program

element is acceptable.

Acceptance Criteria. The applicant stated, in Section B.1.18 of Appendix B to the LRA, that it

evaluates flaws detected during examination by comparing the examination results to the

acceptance standards established in ASME Code, Section Xl.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The staff reviewed the applicant's Acceptance Criteria program element and finds

that the applicant deems any flaws discovered in the process of performing the inspections as

unacceptable and implements corrective measures. Acceptance criteria are based on existing

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codes. On this basis, the staff finds that the Acceptance Criteria program element is

acceptable.

Operating Experience. The applicant stated, in Section B.1.18 of Appendix B to the LRA, that

the augmented inspections to be added before the period of extended operation are new.

However, extensive industry operating experience supports the monitoring techniques used in

this program. Operating experience at CNP will provide input to adjust the program, as needed,

and to develop new augmented inspections.

The staff reviewed the applicant's ISI summary review of flaws that it analyzed to the end of the

service life of the component. The staff finds that the applicant's ISI inspection results identify

no analytical flaw evaluations performed in accordance with Subsection IWB-3600 for the

service life of the component. Although the data were reported for the Metal Fatigue Program,

the staff finds that they apply to the Inservice Inspection-ASME Section Xl, Augmented

Inspection Program.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff finds that CNP AMP B.1.18 adequately manages the aging

effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.21 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Inservice Inspection-ASME Section Xl, Augmented Inspections Program and stated

that the program will manage the effects of aging on selected components outside the

jurisdiction of ASME Code, Section Xl. To the extent practical, augmented inspections will be

consistent with the applicable requirements of ASME Code, Section XI (i.e., selection of

inspection methods, inspection frequency, percentage of components examined within a

population, and acceptance criteria). This program requires enhancements that will be

implemented before the period of extended operation.

The staff reviewed 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 the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs 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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3.0.3.3.7 Instrument Air Quality

Summary of Technical Information in the Application

Section B.1.19, uInstrument Air Quality," of the LRA describes the applicant's Instrument Air

Quality Program; In the LRA, the applicant stated that this existing plant-specific'program

prevents and mitigates aging effects on control air system components by maintaining'the

system free of water and significant contaminants. The GALL Report has no comparable

program. The applicant also stated that the control air system is part of the CA system.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in'Section

B.1.19 of Appendix B to the LRA, regarding the applicant's demonstration of the Instrumeht Air'

Quality Program, to ensure that it will adequately manage the effects of aging, as discussed

above, so that the intended functions of SCs will be maintained consistent with the CLB

throughout the period of extended operation. -

The staff reviewed the Instrument Air Quality Program against the AMP elements found in

Table A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's

management of aging effects through the effective incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated inSection 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scope of Program. The applicant stated, in Section B.1.19 of Appendix B to the LRA, that the'

program applies to those components within the scope of license renewal and subject to an

AMR that are supplied with control air where pressure boundary integrity is required for the

component to perform its intended function.

The staff confirmed that the Scope of Program element satisfies the criteria defined in Appendix

A.1 to 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, in Section B.1.19 of Appendix B to the LRA, that it

monitors and maintains system air quality in accordance with CNP testing and inspection plans,

which are designed to ensure that the control air system and equipment meet specified

operating requirements. 'These requirements are derived from guidelines'presented in

American National Standards Institute (ANSI) Standaird ISA-S7.3-1975, "Quality Standard for

Instrument Air."

After reviewing the applicant's surveillance procedures and holding discussions with the

applicant's responsible engineer, the staff finds that the applicant employs effective methods to'

prevent degradation of instrument air quality. The staff also confirmed that the Preventive ' ' -

Actions program element satisfies the criteria'defined in'Appendix A.1 to 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.

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Parameters Monitored or Inspected. The applicant stated, in Section B.1.1 9 of Appendix B to

the LRA, that this program periodically monitors the control air system air quality pursuant to the

performance requirements in ANSI Standard ISA-S7.3-1975, including (1) maximum dewpoint (monitored approximately weekly), (2) particulate size (afterfilter differential pressure monitored

daily), and (3) dryer condition inspection (monitored approximately monthly). In addition, the

applicant proposed to enhance plant procedures to more clearly specify frequencies for the

dewpoint and dryer tours.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The parameters monitored or inspected are linked to the aging effects pertinent to component intended functions. The parameters monitored are not necessarily the specific parameters being controlled to achieve the prevention or mitigation of aging effects; however, the selection of parameters is appropriate. For example, the surveillance program monitors to

confirm that air system temperatures remain above the dew point. In another instance, particulates are not directly measured, but filter replacement that provides effective control is

required. Maintenance and procurement documents were reviewed to confirm that the

specified equipment is suitable for maintaining air quality within the required limits. On this

basis, the staff finds that the Parameters Monitored or Inspected program element is

acceptable.

Detection of Aging Effects. The applicant stated, in Section B.1.19 of Appendix B to the LRA, that it follows ANSI Standard ISA-S7.3-1975 guidelines to ensure timely detection of

degradation of the control air system function. Degradation of the piping and equipment would

become evident by observation of excessive corrosion, discovery of unacceptable leakage rates, or failure of the system or equipment to meet specified performance limits. This program is credited with managing the loss of material of the carbon steel, copper, and brass/bronze

components in the control air systems.

The staff confirmed that, with the enhancement to clearly specify frequencies for dewpoint and

dryer tours, this program element satisfies the criteria defined in Appendix A.1 to the SRP-LR.

The program is primarily preventive in approach and emphasizes maintenance of air system quality rather than detection of degradation in the components it serves. On this basis, the staff

finds that the Detection of Aging Effects program element is acceptable.

Monitoring and Trending. The applicant stated, in Section B.1.19 of Appendix B to the LRA,

that it maintains trends for dewpoint in a trending database. It checks the control air afterfilter

differential pressure daily.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The surveillance and maintenance procedures specify the Monitoring and

Trending activities. On this basis, the staff finds that the Monitoring and Trending program element is acceptable.

AcceDtance Criteria The applicant stated, in Appendix B, Section B.1.19, to the LRA that the

dewpoint at line pressure must be at least -7.8 CC (18 OF) below the minimum temperature to

which any part of the instrument air system is exposed at any season of the year. In no case

should dewpoint at line pressure exceed 3 0C (35 OF).

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The applicant also stated in the LRA that plant procedures prescribe the removal of the

afterfilter from service based on a specified high differential pressure limit (commitment from

GL 88-14, "Instrument Air Supply System Problems Affecting Safety-Related Equipment").

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR and that the applicant provided appropriate acceptance criteria in the form of

prescribed numerical limits. On this basis, the staff finds the Acceptance Criteria program

element acceptable.

Operating Experience. The applicant stated, in Section B.1.19 of Appendix B to the LRA, that

the NRC issued GL 88-14 based on industry operating experience with air systems. The

applicant also stated that the Instrument Air Quality Program is based on program elements

specified in the GL. The applicant documents instrument air quality that does not meet the

administrative control criteria for sampling through the Corrective Action Program, which

includes trending for adverse conditions and repetitive failures of system components.

The applicant stated in the LRA that the lack of a significant number of CRs regarding loss of

material caused by corrosion in the air systems indicates that the program has been effective in

preventing the effects of aging. As an example, a CR documented failure of the Unit 2 east

control air dryer which,- if left uncorrected, could have led to a failure to comply with the

dewpoint requirements for air quality.

The staff reviewed the applicant's responses to concerns arising from industry experience with

air systems. The staff finds that the applicant has had only a small number of CRs related to air

systems. This suggests that the preventive approach taken has been successful. -

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that Instrument Air Quality Program adequately

manages the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.22 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Instrument Air Quality Program and stated that the program periodically documents the

control air system air quality for maximum dew point, particulate size, and dryer condition,

pursuant to the performance requirements of ANSI Standard ISA-S7.3-1975. This program

ensures that the control air supplied to components within the scope of license renewal is

maintained free of water and significant contaminants: This program requires an enhancement

that will be implemented before the period of extended operation. The commitment to perform

the enhancement is item number 11 of Appendix A of this SER.

The staff reviewed 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 the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

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functions of SCs 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).

3.0.3.3.8 Oil Analysis

Summary of Technical Information in the Application

Section B.1.23, "Oil Analysis," of the LRA describes the applicant's Oil Analysis Program. The GALL Report has no comparable program. The applicant credited this plant-specific program with maintaining oil systems free of contaminants (primarily water and particulates), thereby preserving an environment that is not conducive to loss of material, cracking, or fouling.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section B.1.23 of Appendix B to the LRA regarding the applicant's demonstration of the Oil Analysis Program to ensure that it will adequately manage the effects of aging, as discussed above, so that the intended functions of SCs will be maintained consistent with the CLB throughout the period of extended operation.

The staff reviewed the Oil Analysis Program against the AMP elements found in Table A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's management of aging effects through the effective incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, provided in Section

3.0.4 of this SER, includes the corrective actions, confirmation process, and administrative

controls. The following paragraphs discuss the remaining seven elements.

Scope of Program. The applicant stated that this program encompasses periodic sampling of the lubricating oil to which plant components subject to an AMR are exposed. The components are maintained in a list of plant equipment included in the program.

The applicant stated that Oil Analysis Program will manage aging effects on the ECCS

components wetted by lubricating oil, RCP bearing oil coolers, EDG lubricating oil system components, fire pump diesel engine lubricating oil system components, security diesel engine lubricating oil system components, and AFW pump turbine lubricating oil components. The applicant used Institute of Nuclear Power Operations (INPO) 89-009, Good Practice MA-316, "Plant Predictive Maintenance," as a basis for the initial selection of equipment.

The staff confirmed that the applicant identified the specific components for which the Oil Analysis Program manages aging. The Oil Analysis Program includes the lubricating oil to which these components are exposed. The Scope of Program element satisfies the criteria

defined in Appendix A.1 to the SRP-LR. On this basis, the staff finds that the applicant's proposed scope is acceptable.

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Preventive Actions. The applicant stated that the program maintains oil systems free of

contaminants (including water and particulates), thereby preserving an environment that is not

conducive to corrosion.

The staff confirmed that the Preventive Actions program element satisfies the criteria defined in

Appendix A.1 to 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 or Inspected. The applicant stated that the program monitors

contaminants that contribute to the aging effects of concern, such as particle contaminants and

water content.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The Oil Analysis 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 that periodic sampling and compliance with

the acceptance criteria provide assurance that lubricating oil contaminants do not exceed

acceptable levels. The applicant stated that this program manages the aging effects of (1) loss

of material (including that caused by selective leaching) and fouling for the ECCS components

wetted by lubricating oil, (2) loss of material for RCP bearing oil coolers, (3) loss of material

(including that caused by selective leaching), cracking, and fouling for EDG lubricating oil

system components, (4) loss of material (including that caused by selective leaching) and

fouling for the fire pump diesel engine lubricating oil system components, (5) loss of material

(including that caused by selective leaching) for security diesel engine lubricating oil system

components, and (6) loss of material (including that caused by selective leaching) and fouling

for AFW pump turbine lubricating oil components. The applicant scheduled routine oil sampling

and may adjust the scheduled sampling dates and intervals according to recommendations

from the analysis laboratory, plant management, and engineering personnel.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. Sampling from a population does not apply 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. The applicant used

appropriate industry standards in the development of sampling methods and frequencies. On

this basis, the staff finds that the Detection of Aging Effects program element is acceptable.

Monitoring and Trending. The applicant stated that the oil trending database contains the data

obtained through the implementation of this program.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. Trending of the analysis results enhances the applicant's ability to detect aging

effects before a loss of intended function occurs. On this basis, the staff finds that the

Monitoring and Trending program element is acceptable.

Acceptance Criteria. The applicant stated that it reviews data received from the testing

laboratories and documents evaluations of reports indicating an adverse trend or significant

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exception. It has set alert levels to initiate corrective action based on wear particle count, viscosity, and water content. Appropriate corrective actions are initiated when concerns

regarding equipment or lubricant conditions are indicated.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

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 corrective measures. On this basis, the staff finds the

Acceptance Criteria program element acceptable.

Ogerating Experience. The applicant stated that a review of operating experience pertaining to

the Oil Analysis Program determined that program enhancements have been made based on

industry and plant-specific operating experience. For example, it evaluated the potential for

possible incompatibility between EDG fuel oil and lubricating oil identified at another nuclear

power plant and made a program change to ensure that the problem was addressed. The

review of CRs indicates that the program has detected conditions at levels below which aging degradation is expected to occur.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the Oil Analysis Program adequately

manages the aging effects that have been observed at the applicant's plant and will continue to

do so during the period of extended operation.

UFSAR Supplement

In Section A.2.1.26 of Appendix A to the LRA, the applicant provided the UFSAR Supplement for the Oil Analysis Program and stated that the lubricating oil environment in the mechanical

systems within the scope of license renewal is maintained to the required quality. By monitoring oil quality, the Oil Analysis 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 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 the applicant has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs 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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3.0.3.3.9 Pressurizer Examinations

Summary of Technical Information in the Application

Section B.1.24, "Pressurizer Examinations," of the LRA describes the applicant's Pressurizer

Examinations Program. ,In the LRA, the applicant stated that this plant-specific program has no

comparable GALL program. As discussed in WCAPA14574-A, "License Renewal Evaluation: -

Aging Management for Pressurizers," cracking of the pressurizer cladding (and items attached

to the cladding) may propagate into the underlying ferritic steel. In addition, the pressurizer

spray head is susceptible to cracking and reduction of fracture toughness.' This program -

identifies degradation that could potentially cause loss of intended function of these pressurizer

components.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section

B.1.24 of Appendix B to the LRA regarding the applicant's demonstration of the Pressurizer

Examinations Program to ensure that it will adequately manage the effects of aging,- as

discussed above, so that the intended functions of SCs 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

Table A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's

management of aging effects through the effective incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, discussed in

Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.- :

RAI B.1.24-1

Scope of Program. The applicant states that the pressurizer examinations assess the cladding

and attachment welds to the cladding of the pressurizer. Examinations of the condition of the

pressurizer spray head, spray head locking bar, and coupling will be added to the scope of this

program. The staff could not determine whether the scope includes nickel-alloy bimetallic

welds used to attach penetrations to the pressurizer, and, if not, whether these nickel-alloy- -

based bimetallic penetration attachment welds are managed through another AMP. .The staff

addressed this concern in RAI B.1.24-1. The applicant responded in its letter dated August 19,-

2004, that no nozzles are attached to the pressurizer with nickel-based alloy welds. It stated

further that the surge, spray, relief, and safety nozzle-to-piping safe end connections are

buttered with nickel-alloy weld material prior to attachment of the stainless steel safe ends with

nickel-alloy weld material, and the Alloy.600 Aging Management Program will manage the aging

effects for these welds. The staff considers this response satisfactory because it has confirmed -

that all pressurizer components having nickel-alloy weld material are outside the scope of the

Pressurizer Examinations Program, and will be managed by another AMP. Therefore, RAI

B.1.24-1 is resolved, and Bulletin 2004-01, which concerns the inspection of Alloy 82/182/600

materials in pressurizer penetrations, is not relevant to this AMP. - -

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Preventive Actions. In Section B.1.24 of Appendix B to the LRA, the applicant stated that the

Pressurizer Examinations Program is an examination program and will involve no actions to

prevent aging effects or mitigate aging degradation.

The staff confirmed that the Preventive Actions program element satisfies the criteria defined in

Appendix A.1 to the SRP-LR. The staff did not identify the need for preventive actions for the

Pressurizer Examinations Program because it is a condition monitoring program.

Parameters Monitored or Inspected The applicant stated, in Section B.1.24 of Appendix B to

the LRA, that to provide assurance that cracking of the pressurizer cladding and attachment

welds to the cladding has not propagated into the underlying base metal of the pressurizer, it

will perform volumetric examination of pressurizer items that are susceptible to thermal fatigue.

Cracking of the pressurizer stainless steel cladding would most likely result from thermal

fatigue. The stainless steel clad item with the highest fatigue cumulative usage factor is the

circumferential weld at the shell-to-head junction. In accordance with ASME Code, Section XI,

Examination Category B-B, the applicant will perform volumetric examination of essentially 100

percent of the circumferential shell-to-head weld at each inspection interval. 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 cladding that

may propagate to the underlying ferritic steel. The weld that connects the surge nozzle to the

lower head will receive volumetric examination at each inspection interval 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 applicant stated that it will enhance the program to include a one-time condition

assessment of the spray head, spray head locking bar, and coupling.

The staff confirmed that this program element satisfies the criteria defined in Appendix A to 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 program element is acceptable.

RAI B. 1.24-2

Detection of Apino Effects. Detection of cracking in the pressurizer cladding is achieved

through periodic volumetric inspection procedures that satisfy ASME Code Section Xl

requirements, and is therefore acceptable. The applicant will determine the condition of the

internal spray head, spray head locking bar, and coupling by a one-time visual examination (VT3) of these components in either Unit 1 or Unit 2. This examination will be. performed prior to

the period of extended operation to accepted ASME Code Section Xl methods and standards.

Since the spray head and its associated components are subject to severe thermal cycling, the

applicant did not provide an adequate justification to demonstrate that a VT-3 examination is

adequate to detect a potential flaw in the spray head which could lead to the failure of the

components. In addition, the applicant provided insufficient information for the staff to conclude

that the proposed one-time inspection of these components in either Unit 1 or Unit 2 is

adequate. The staff addressed this concern in RAI B.1.24-2.

The applicant made a final response to RAI B.1.24-2 in the letter dated October 18, 2004,

which indicates that the pressurizer spray components are not relied upon for the mitigation of

design basis events (DBEs), and are not required to demonstrate compliance with the regulated

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events including fire protection, as addressed in Appendix R, uFire Protection Program for

Nuclear Power Facilities Operating Prior to January 1, 1979." Consequently, the applicant

concluded the following:

The spray heads and associated components do not perform a license renewal

intended function and are not required to satisfy the safety related systems,

structures, or components scoping'criteria of 10 CFR 54.4(a)(1), the nonsafety

related scoping criteria of 10 CFR 54.4(a)(2), or the regulated events scoping

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

Nevertheless, the applicant plans to improve the Pressurizer Examinations Program to perform

a one-time VT-3 visual examination of these components in' one unit as part of its license

renewal commitments. This is Commitment #15 in Appendix A of this SER.

The staff considers that it is adequate to perform a one-time VT-3 visual examination of spray

head components in one unit because (1) the components are not required to satisfy the safety

related, nonsafety related, or the regulated events scoping criteria, (2) to date, the industry has

not reported any incidents of loose part generation due to fracture of the spray head

components, and (3) corrective actions, including replacement, will be considered after an

evaluation of the one-time examination results. Based on this consideration, the staff

concludes that the response to RAI B.1.24-2 satisfactory, and RAI B.1.24-2 is closed. This

attribute is consistent with the GALL Report.

Monitoring and Trending. The applicant stated, in Section B.1.24 of Appendix B to the LRA,

that during the course of the inspections, nondestructive examinations will characterize the

extent of surface or volumetric flaws. It will record anomalous indications that are signs of

degradation'on NDE reports in accordance with plant procedures. As the inspection of the

pressurizer spray head, spray head locking bar, and coupling is a one-time inspection, no

monitoring or trending will be completed for this activity; However, the applicant will determine

the need for subsequent inspections after evaluating the results of the inspection. All other

examinations are part of the ASME Code, Section Xl, required inspections and will be

monitored in accordance with ASME Code, Section Xl.'

The staff confirmed that this program element satisfies the criteria defined in Appendix A to the

SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect aging

effects before a loss of intended function occurs. On this basis, the staff finds that the

Monitoring and Trending program element is acceptable.

Acceptance Criteria. The applicant stated, in Section B.1.24 of Appendix B to the LRA, that the

acceptance criteria for volumetric examinations will be in accordance with ASME Code, Section

Xl, Subsections IWB-3510 and IWB-3512. The acceptance standards for the'visual

examinations will be in accordance with ASME Code, Section Xl, examinations (VT-3).

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

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 considered

unacceptable and corrective measures implemented. On that basis, the staff finds that the

Acceptance Criteria program element is acceptable.

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I

RAI B. 1.24-3

Operating Experience. Section B.1.24 of the LRA states that the volumetric inspections have

been performed with inservice inspection techniques that have been proven effective within the

industry at detecting cracking. The applicant did not provide plant-specific or industry

experience for volumetric or visual examination of pressurizer cladding and spray head

components from the activities related to its Pressurizer Examinations Program for CNP. The

staff addressed this issue in RAI B.1.24-3. The applicant responded in the letter dated August

19, 2004 that WCAP-14574-A and its associated safety evaluation (SE) documented that

volumetric examination had been used to support the acceptable disposition of pressurizer

cladding cracking at the Haddam Neck Plant. It further stated that volumetric examinations of

essentially 100 percent of the circumferential shell-to-head weld (Examination Category B-B)

and the weld between the surge nozzle and the pressurizer vessel lower head (Examination

Category B-D) performed each inspection interval in accordance with ASME Code, Section Xl,

provide monitoring for cracking of the cladding that may extend into the underlying base metal.

A complete pressurizer inspection history for CNP was provided in the applicant's response to

Bulletin 2004-01 dated July 26, 2004, which is under staff review. Since the applicant has

reported the plant-specific pressurizer inspection history and industry effort in detecting, sizing,

and disposition of cracking in the pressurizer cladding, which is a rare event and is one of the

degradation issues discussed in WCAP-14574-A, RAI B.1.24-3 is closed.

UFSAR Supplement

In Section A.2.1.27 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Pressurizer Examinations Program and stated that the program manages cracking of

the pressurizer cladding (and items attached to the cladding) that may propagate into the

underlying ferritic steel. This program will also determine the condition of the internal spray

head, spray head locking bar, and coupling by a one-time visual examination of these

components in one CNP unit. This program requires enhancements that will be implemented

before the period of extended operation.

The staff reviewed 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 the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs 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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3.0.3.3.10 Preventive Maintenance v

Summary of Technical Information in the Application

Section B.1.25,-"Prevehtive Maintenance," of the LRA describes the applicant's Preventive

Maintenance Program. In the LRA, the applicant credited this plant-specific program with

maintaining plant SSCs at the quality level required for the safe and reliable operation of the

plant. The GALL Report has no comparable program. The program comprises those

preventive maintenance tasks that are intended to sustain plant equipment within design

parameters and maintain the equipment's intrinsic reliability.

Staff Evaluation -

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section

B.1.25 of Appendix B to the LRA regarding the applicant's demonstration of the Preventive

Maintenance Program to ensure that it will adequately manage the effects of aging, as

discussed above, so that the intended functions of SCs will be maintained consistent with the

CLB throughout the period of extended operation.

The staff reviewed the Preventive Maintenance Program against the AMP elements found in

Table A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's

management of aging effects through the effective incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated in

Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scope of Program. The applicant stated, in Section B.1.25 of Appendix B to the LRA, that this

program element encompasses those tasks credited with managing the aging effects identified

in the LRA. The applicant described the SC-specific preventive maintenance activities credited

for license renewal under the Detection of Aging Effects program element.

The staff confirmed that the Scope of Program element satisfies the criteria defined in Appendix

A.1 to the SRP-LR. The proposed scope identifies the programr element under which the

specific components for which the program manages aging are discussed. On this basis, the

staff finds that the applicaint's proposed program scope is acceptable.

Preventive Actions. The applicant stated, in Section B.1.25 of Appendix B to the LRA, that the

inspection and testing activities used to identify component aging effects do not prevent aging

effects. However, implementation of these activities enables the inspectors to detect aging

effects and allow for corrective actions before loss of intended function.

The staff confirmed that the Preventive Actions program element satisfies the criteria defined in

Appendix A.1 to the SRP-LR. The periodic surveillance and Preventive Maintenance Program

activities will identify component aging effects and prevent failures of components that might be

caused by aging 6ffects.' On this basis, the staff finds that the Preventive Action program

element is acceptable.

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Parameters Monitored or Inspected. The applicant stated, in Section B.1.25 of Appendix B to

the LRA, that the program documents and specific preventive maintenance procedures address

parameters such as surface condition, cracking, and other indications of aging effects.

Inspection and testing activities monitor various parameters, including surface condition,

presence of corrosion products, and signs of cracking.

The staff confirmed that this program element satisfies the criteria defined in Appendix A to the

SRP-LR. On the basis of interviews with the applicant's technical staff, the staff finds the

applicant's Parameters Monitored or Inspected program element to be acceptable.

Detection of Aging Effects. The applicant stated, in Section B.1.25 of Appendix B to the LRA,

that preventive maintenance activities provide for periodic component inspections and testing to

detect aging effects. Inspection intervals are established such that they provide for the timely

detection of degradation. Inspection intervals depend on the component material and

environment and take into consideration industry and plant-specific operating experience and

manufacturer's recommendations.

The extent and schedule of inspections and testing assure detection of component degradation

before the loss of intended functions. The program uses established techniques, such as visual

inspections.

The program includes inspections of the centrifugal charging pump casing cladding, as

identified in NRC IN 80-38, "Cracking in Charging Pump Casing Cladding," to manage the

component-specific aging effect of cladding cracking caused by high localized stresses. After

locations of rust or boric acid deposits are mapped, liquid penetrant examinations are used to

identify indications of aging. Damaged areas are excavated and reclad with stainless steel.

Base metal is repaired if necessary.

Numerous EDG components are inspected in a general fashion, rather than

component-by-component listings. This program currently ensures that loss of material,

cracking, fouling, and change in material properties are managed for EDG subsystem

components. The applicant will enhance the program to manage the aging effects of cracking

and change of material properties for the emergency diesel engine elastomer flex hoses or

tubing, using visual inspection and replacement as needed. The staff addressed the methods

used to monitor a change of material properties of elastomers in flex hoses or tubing associated

with the EDG system components in RAI 3.3.3-2, which is discussed in Section 3.3.2.3.8 of this

SER.

The program currently performs inspections of control room ventilation air handler unit

components, AFW pump room cooling unit components, and the EDG ventilation system. The

applicant will enhance the tasks for the control room ventilation air handler packages to include

inspection of the heat exchanger tubes and flex joints. These inspections will ensure that loss

of material and fouling are managed for the stainless steel heat exchanger tubes, and that

changes in material properties and cracking are managed for the elastomer flex joints. The

applicant will enhance the tasks for the AFW pump room cooling unit components to include

inspection of the internal evaporator tubes, valves, and tubing. These inspections will ensure

that loss of material and fouling are managed for the copper alloy components within these

units. The applicant will enhance the tasks for the EDG ventilation system to include inspection

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of the flex joints. These inspections will ensure that changes in material properties and

cracking are managed for the elastomer flex joints.

In addition, the applicant will enhance the fire protection system preventive maintenance

activities to perform inspections of RCP lubricating oil leakage collection components. The

applicant will replace any damaged components that are found to ensure that loss of material is

managed and that the intended function of pressure boundary is maintained for the period of

extended operation.

The applicant will enhance the program to manage cracking and change in material properties

for the rubber hoses in the CA system that require an AMR. This activity will include visual

inspection and replacement as needed. The applicant will also enhance the program to

manage cracking and change of material properties for the rubber hoses for the postaccident

containment hydrogen monitoring system (PACHMS) reagent gas supply. This will include

visual inspection and replacement as needed. The applicant will enhance the program to

manage cracking and change of material properties for the security diesel engine elastomer flex

hoses or tubing, including visual inspection and replacement as needed. The program will also

be enhanced to manage cracking and change in material properties of the AFW system

elastomer CST floating head seals, including visual inspection and replacement as needed.

Finally, the applicant will specify acceptance criteria and corrective actions as needed for the

enhancements. The enhancements are cited in Commitment #16 in Appendix A of this SER.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The measurements and inspections use a frequency and sample size based on

operating experience 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, in Section B.1.25 of Appendix B to the LRA,

that administrative controls reference activities for monitoring systems and components to

permit early detection of degradation. These activities include visual examinations for

corrosion, cracking, fouling, leaking and physical condition, mechanical damage, and loose or

missing hardware, as appropriate..

The CNP's Corrective Action Program is applicable to this program. This provides reasonable

assurance that the applicant will identify trends entailing repeat failures to meet the acceptance

criteria and address them with appropriate corrective actions.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect

aging effects before a loss of intended function occurs. On the basis of its review of the

Monitoring and Trending program element, the staff finds it acceptable.

AcceDtance Criteria. The applicant stated, in Section B.1.25 of Appendix B to the LRA, that

specific inspection and testing procedures define the program acceptance criteria. The

acceptance criteria confirm component integrity by verifying the absence of aging effects or by

comparing applicable parameters to limits based on the relevant intended functions established

by the plant design basis. The applicant's Corrective Action Program addresses unacceptable

indications of aging effects.

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The staff confirmed that this program element satisfies the criteria defined in Appendix A to the

SRP-LR. The staff reviewed a selection of the repetitive tasks and associated procedures. In

all cases where an aging effect had been identified, appropriate acceptance criteria were

provided. Therefore, the staff finds the Acceptance Criteria program element to be acceptable.

Operating Experience. The applicant stated, in Section B.1.25 of Appendix B to the LRA, that

the review of operating experience included CRs, program health reports, assessment reports,

NRC inspection reports, and LERs.

The applicant stated in the LRA that it overhauled the program as part of the 1997-2000 plant

restart effort. Program improvements incorporated proven industry practices and addressed

self-identified issues. In 1999, the applicant benchmarked the Preventive Maintenance

Program using programs considered to be among the best in the industry. The NRC conducted

a special inspection in 1999 and concluded that the preventive maintenance activities were

adequate to support restart of the plant. The applicant also stated that to maintain the program,

the preventive maintenance group reviews industry operating experience via the Corrective

Action Program and factors it into existing or new preventive maintenance tasks, when

applicable.

The staff noted that plant operating experience with respect to the Preventive Maintenance

Program is extensive. The applicant did not document operating experience for the Preventive

Maintenance Program that is specific to the aging effects of concern or the components

addressed; however, the staff concluded that the use of the Corrective Action Program and

reviews of industry experience are a satisfactory method for ensuring that operating experience

is factored into the program appropriately.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the Preventive Maintenance Program

adequately manages the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.28 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Preventive Maintenance Program and stated that the program comprises those

preventive maintenance tasks which are intended to sustain plant equipment within design

parameters and maintain the equipment's intrinsic reliability. Preventive maintenance activities

will provide for periodic component inspections and testing to detect the various aging effects

applicable to those components included in the scope of the AMP for license renewal. The

applicant stated that it will implement the required program enhancements before the period of

extended operation.

The staff reviewed 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 the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

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functions of SCs will be maintairied 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 Structures Monitoring-Divider Barrier Seal Inspection

Summary of Technical Information in the Application

Section B.1.34, "Structures Monitoring-Divider Barrier Seal Inspection," of the LRA describes

the applicant's'Structures Monitoring-Divider Barrier Seal Inspection Program. In the LRA, the

applicant stated that this is a plant-specific pr6gram. The divider barrier in each containment is

the physical boundary that separates upper containment from lower containment. Several

containment internal structures constitute the divider barrier. Elastomeric seals are provided for

penetrations and openings through the divider barrier where it is necessary to limit potential ice

condenser bypass leakage subsequent to a postulated pipe rupture or loss of coolant accident.

Cracking and change in material properties are AERMs for the pressure seals.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section

B.1.34 of Appendix B to the LRA, regarding the applicant's demonstration of the Structures

Monitoring-Divider Barrier Seal Inspection Program to ensure that it will adequately manage

the effects of aging, as discussed above, so that the intended functions of SCs will be

maintained consistent with the CLB throughout the period of extended operation.

The staff reviewed the' Structures Monitoring-Divider Barrier Seal Inspection Program against

the AMP elements found in Table A.1 -1 and Section A.1.2.3 of App~endix A to the SRP-LR and

focused on how the program manages aging effects through the effective inicorporation'of the

10 program elements.

The applicant'indicated that the site-controlled Quality Assurance Program, described in

Section 3.0.4 of this SER, includes the corrective 'actions, confirmation process, and

administrative controls. The following paragraphs describe the remaining seven elements.

Scope of Program. The applicant stated, in Section B.1.34 of Appendix B to the LRA, that this

program covers the containment divider barrier elastomeric pressure seals around penetrations

and openings through the divider barrier.

The staff confirmed that the applicani identified thespecific components for which the program

manages-aging effects, which satisfies the-criteria defined in Appendix AA to the SRP-LR.- On

this basis, the staff finds that the applicant's proposed scope is acceptable. -

Preventive Actions. In Section B.1.34 of Appendix B to the LRA,-the applicant stated that the

Structures Monitoring-Divider Barrier Seal Inspection Program is an inspection program. It will

involve no actions to prevent or mitigate aging degradation.

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The staff confirmed that the Preventive Actions program element satisfies the criteria defined in

Appendix A.1 to the SRP-LR. The staff did not identify the need for preventive actions for CNP

AMP B.1.34 because it is an inspection program.

Parameters Monitored or Inspected. The applicant stated, in Section B.1.34 of Appendix B to

the LRA, that this program monitors cracking and change in the material properties of

elastomeric pressure seals.

The staff reviewed this program element against the criteria defined in Appendix A to the

SRP-LR. The staff reviewed the applicant's procedures which address inspection and testing and describe the parameters for cracking and other geometric discontinuities. The staff did not

identify any test or inspection that would reveal a change in material properties.

RAI B. 1.34-1

During the AMP audit, the staff requested clarification on the method used to monitor a change in material properties of the elastomeric pressure seals. By letter dated April 23, 2004, the

applicant responded that it intended the phrase "change in material properties" to convey a

visual inspection to ensure the absence of apparent deterioration (i.e., cracks or defects in the

sealing surfaces) as discussed in the implementing procedures. Changes in other material

properties are neither monitored nor inspected.

Since cracking is addressed separately and because material properties that may affect the

performance of seals (i.e., hardening and embrittlement) are not addressed, the staff did not

consider this issue resolved. By letter dated August 20, 2004, in RAI B.1.34-1, the staff asked

that the applicant provide a basis for concluding that the elastomeric divider barrier will continue

to perform its design function despite changes in material properties that may not be visible.

The staff had clarified, in an earlier telephone conversation with the applicant, that the

elastomeric pressure seals in question are the penetration seals installed around containment

penetrations and openings through the divider barrier. The applicant had stated that the main

divider barrier seals are inspected and replaced based on their condition, in accordance with

CNP Technical Specification Surveillance Requirement 4.6.5.9, and are not subject to an AMR.

Additionally, the applicant noted that the divider barrier personnel access door and equipment hatch seals are visually inspected before containment closure during each outage, in

accordance with CNP Technical Specification Surveillance Requirement 4.6.5.5, and are also

not subject to an AMR.

By letter dated September 2, 2004, in its response to RAI B. 1.34-1, the applicant stated that

LRA Table 3.5.2-1, page 3.5.2-1, identifies the divider barrier penetration seals under the

component type "removable gate (bulkhead) seals." Table 3.5.2-5, page 3.5-66 of the LRA, identifies this under the component type "divider barrier penetration seals." These elastomeric

seals are subject to cracking and change in material properties aging effects and result in

thermal exposure and ionizing radiation aging mechanisms. Visual inspection readily identifies

the noteworthy effects of these aging mechanisms of elongation, cracking, swelling, and

melting. Therefore, the applicant stated that visual inspections would observe these effects as

abnormalities indicative of material degradation before aging would challenge the intended

function of the seals.

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On the basis of its review of the response to RAI B.1.34-1, the staff finds that the applicant's

response is acceptable because visual inspection will adequately monitor change in the

material properties of the penetration divider barrier seals so that the intended functions of SCs

will be maintained consistent withthe CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). Therefore, the staff finds that the issue is resolved and that this program

element satisfies the criteria defined in Appendix A.1 to the SRP-LR.

Detection of Aging Effects. The applicant stated, in Section B.1.34-of Appendix B to the LRA,

that the program detects cracking and change in material properties before loss of the pressure

seals' intended functions. The seals around penetrations and openings (including the bulkhead

gate) are visually inspected to ensure the absence of apparent deterioration (cracks or defects),

and the frequency of inspection is at least once every 10 years.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The applicant will inspect the divider barrier seals at least once every 10 years.

Visual inspections will examine the pressure seals for signs of cracking or surface defects

properties before the loss of intended function.

Monitoring and Trending. The applicant stated, in Section B.1.34 of Appendix B to the LRA,

that this program monitors aging effects through visual examination of the seals. The

Corrective Action Program provides reasonable assurance that the applicant will identify

repeated failures to meet acceptance criteria and addressed them with appropriate corrective

actions.

The staff confirms that, for visual inspection, this program element satisfies the criteria defined

in Appendix A.1 to the SRP-LR. The plant procedures describe the documentation and

monitoring of visual inspection results.

AcceDtance Criteria. The applicant stated, in Section B.1.34 of Appendix B to the LRA, that

seals must be free of unacceptable deterioration (excessive cracks or defects) and

unacceptable misalignment.

The staff reviewed this program element to determine if it satisfies the criteria defined in

Appendix A.1 to the SRP-LR. The applicant will consider any degradation that could lead to a

loss of function to be unacceptable and implement corrective measures.

RAI B. 1.34-2

The acceptance criteria described in implementing procedures include evidence of chemical

attack, radiation damage, or changes in physical appearance. The applicant did not provide

any guidance as to how it would evaluate these effects.

By letter dated August 20, 2004, in RAI B.1.34-2, the staff requested clarification on the.

acceptance criteria for evaluating changes in material properties of elastomers, specifically, the

pressure seals (divider barrier). The staff determined that implementing procedures mention -

evidence of chemical attack, radiation damage, or changes in physical appearance. The staff

asked the applicant to clarify how it will evaluate these and confirm that visual evidence of

degradation will precede a loss of function.

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By letter dated September 2, 2004, in its response to RAI B.1.34-2, the applicant stated that the

acceptance criteria for these elastomers include the absence of elastomeric seal material

abnormalities, such as swelling, surface cracking, discoloration, surface peeling, separation,

melting, holes, ruptures, abrasions, or other changes in appearance. The applicant stated that

it will evaluate any abnormality and degradation under the Corrective Action Program to ensure

that the pressure boundary function of the degraded seal is intact.

On the basis of its review of the applicant's response to RAI B.1.34-2, the staff finds it

acceptable because visual inspection of the elastomeric seals will detect degradation before the

loss of intended function. The staff concludes that the applicant has satisfied the acceptance

criteria defined in Appendix A.1 to the SRP-LR.

Operating Experience. The applicant stated, in Section B.1.34 of Appendix B to the LRA, that

its operating experience relative to the Structures Monitoring-Divider Barrier Seal Inspection

Program includes CRs and LERs. The review revealed that the program monitors and detects

the aging of the elastomer seals before loss of intended function occurs. The CRs include all

aspects of the divider barrier seal and indicate no pattern of repeat conditions. For example, a

CR documented the adequacy of inspection and replacement criteria for seals covered by the

program. Another CR and associated LERs document the correction of ice condenser bypass

leakage in excess of the design basis through the implementation of design changes.

The applicant also stated that the limited number of ice condenser containments has resulted in

minimal industry operating experience. The applicant did not identify any examples of industry

experience relative to the CNP plants.

The staff reviewed one of the applicant CRs which describes operating experience from the

existing barrier seal inspection and monitoring program. The staff recognizes that the

Corrective Action Program, which captures internal and external plant operating experience

issues, will provide reasonable assurance that operating experience is reviewed and

incorporated in the future to provide objective evidence to support the conclusion that the

effects of aging are adequately managed.

On the basis of its review and discussions with the applicant's technical staff, the staff

concludes that the Structures Monitoring-Divider Barrier Seal Inspection Program will

adequately manage the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.37 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Structures Monitoring-Divider Barrier Seal Inspection Program. The program detects

cracking and change in material properties of elastomeric pressure seals for penetrations and

openings through the containment divider barrier. The program detects aging effects through

visual examination of the seals.

The staff reviewed 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).

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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 it will adequately manage the effects of aging so that the intended

functions of SCs 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).

3.0.3.3.12 Structures Monitoring-Ice Basket Inspection

Summary of Technical Information in the Application

Section B.1.35, "Structures Monitoring-Ice Basket Inspection," of the LRA describes the

applicant's Structures Monitoring-Ice Basket Inspection Program. The GALL Report has no

comparable program. In the LRA, the applicant credited this plant-specific program with

providing instructions to verify that ice condenser baskets are free of detrimental structural

wear, cracks, corrosion, or any other noticeable damage. The functional integrity of the ice

condenser baskets ensures that the ice condenser can perform its intended safety function.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section

B.1.35 of Appendix B to the LRA, regarding the applicant's demonstration of the Structures

Monitoring-Ice Basket Inspection Program to ensure that it will adequately manage the effects

of aging, as discussed above, so that the intended functions of SCs will be maintained

consistent with the CLB throughout the period of extended operation.

The staff reviewed the Structures Monitoring-Ice Basket Inspection Program against the AMPelements found in- Table A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused

on the program's management of aging effects through the effective incorporation of the 10

program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated in

Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scope of Program. The applicant stated, in Section B.1.35 of Appendix B to the LRA, that the

program verifies that the ice condenser baskets are operable. Technical specifications mandate

periodic checking of a sample of ice baskets to verify that they are free of detrimental structural

wear, cracks, corrosion, or other damage.

The staff confirmed that the Scope of Program element satisfies the criteria defined in Appendix

A.1 to 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, in Section B.1.35 of Appendix B to the LRA, that the

Structures Monitoring-Ice Basket Inspection Program is an inspection program. It will involve

no actions to prevent or mitigate aging degradation.

The staff confirmed that the program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The staff did not identify the need for preventive actions for the Structures

Monitoring-Ice Basket Inspection Program because it is a condition monitoring program.

Parameters Monitored or Inspected The applicant stated, in Section B.1.35 of Appendix B to

the LRA, that visual checks are made for the ice basket bottom, top rim, coupling connections,

stiffener rings, weld seams, and ligaments. Ligaments are checked for visible pitting or surface

metal wastage caused by corrosion that is significant enough to dimensionally affect the

ligament.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The Structures Monitoring-Ice Basket Inspection Program activities 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 Section B.1.35 of Appendix B to the LRA, that the program detects loss of material of the ice baskets before loss of structure and

component intended function.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The inspections are conducted, using a frequency and sample size required by plant technical specifications, to detect the presence and extent of aging effects. On that basis, the staff finds that the Detection of Aging Effects program element is acceptable.

Monitoring and Trending. The applicant stated, in Section B.1.35 of Appendix B to the LRA, that results of the ice basket inspections are retained to permit confirmation of the inspection

program effectiveness.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect

aging effects before loss of intended function occurs. On this basis, the staff finds that the

Monitoring and Trending program element is acceptable.

Acceptance Criteria. The applicant stated, in Section B.1.35 of Appendix B to the LRA, that

plant procedures specify the acceptance criteria for the ice basket inspections to ensure that

the ice baskets are free of detrimental structural wear, cracks, corrosion, or other damage.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The applicant will consider any identified deficiencies to be unacceptable and

implement corrective measures. On this basis, the staff finds that the Acceptance Criteria

program element is acceptable.

Operating Experience. The applicant stated, in Section B.1.35 of Appendix B to the LRA, that

its review of relevant operating experience included CRs, LERs, and NRC inspection reports.

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The applicant stated in the LRA that the CRs related to this program identify ice basket damage

and flow passage problems, among others. The applicant found the damage to baskets to

result from improper handling of the baskets during testing (weighing) and refilling, rather than

aging effects. The applicant also stated that it incorporated enhancements into the program

under the corrective actions for these CRs. The NRC inspected the ice condensers in 1998

and did not identify any aging effects in the inspection report.

The staff reviewed the applicant's procedure associated with the Structures Monitoring-Ice

Basket Inspection Program, which provides enhanced instructions for maintaining ice baskets.

The applicant made additional program enhancements under the-Corrective Action Program.

Based on its review, the staff concludes that the applicant has identified operating experience

for the Structures Monitoring-Ice Basket Inspection Program and performed corrective

actions, where needed, as a result.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that CNP AMP B.1.35 adequately manages the

aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.38 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Structures Monitoring-Ice Basket Inspection Program and stated that the program

verifies that ice condenser baskets are free of detrimental structural wear, cracks, corrosion, or

noticeable damage. The program detects loss of material of the ice baskets by visual

inspections, as required by technical specifications.

The staff reviewed 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 the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs 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). . -

3.0.3.3.13 System Testing - - - -

Summary of Technical Information in the Application

Section B.1.37, uSystem Testing," of the LRA describes the applicant's System Testing

Program. The .GALL Report has no comparable program. In the LRA, the applicant credited

this plant-specific program with encompassing a number of miscellaneous system and

component testing activities that manage the effects of aging. These activities typically include

surveillance activities required by the applicant's technical specifications or normal monitoring of

plant operation (i.e., plant log readings or other normal monitoring techniques). In general, the

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applicant conducts these activities on a periodic basis (surveillances) or routinely (logs) during plant operation. The activities verify the continuing capability of safety-related systems and

components to meet established performance requirements.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section

B.1.37 of Appendix B to the LRA regarding the applicant's demonstration of the System Testing Program to ensure that it will adequately manage the effects of aging, as discussed above, so

that the intended functions of SCs will be maintained consistent with the CLB throughout the

period of extended operation.

The staff reviewed the System Testing Program against the AMP elements found in Table

A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's

management of aging effects through the effective incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated in

Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scone of Program. The applicant stated, in Section B.1.37 of Appendix B to the LRA, that the

scope of the program includes (1) the centrifugal charging pump test, (2) ESF ventilation units

testing, (3) control room ventilation units testing, (4) fuel handling area exhaust unit testing, (5) the security diesel test, (6) the letdown orifice test, (7) main steamflow meter monitoring, (8) blowdown system normal operation monitoring, and (9) SFP water level monitoring.

The staff confirmed that the Scope of Program element satisfies the criteria defined in Appendix A.1 to 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, in Section B.1.37 of Appendix B to the LRA, that the

System Testing Program is a monitoring program and will involve no actions to prevent or

mitigate aging degradation.

The staff confirmed that the program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The staff did not identify the need for preventive actions for CNP AMP B.1.37

because it is a condition monitoring program.

Parameters Monitored or Inspected. The applicant stated, in Section B.1.37 of Appendix B to

the LRA, that the program monitors flow rates and pressure.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The program monitors such aging effects as the loss of material in the centrifugal charging pump discharge orifice and aging effects on drains from various ventilation units. - It

addresses fouling and loss of material in parts of the security diesel, as well as loss of material

in the buried fuel oil storage tank, pipe, tubing and associated fittings, starting air components, and (diesel) exhaust gas components. In addition, during the course of plant operation, the,

program monitors the condition of CVCS letdown orifices, blowdown system restricting orifices,

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and main steam system flow restrictors, as well as the level of the SFP. The Site Surveillance

Tracking Database maintains frequencies for monitoring parameters evaluated by the System

Testing Program. On this basis, the staff finds that the Parameters Monitored or Inspected

program element is acceptable.

Detection of Aping Effects. The applicant stated, in Section B.1.37 of Appendix'B to the LRA,

that it will enhance system testing of the centrifugal charging pumps to manage the loss of

material for the centrifugal charging pumps minimum flow orifices and the Unit 1 centrifugal

charging pumps discharge orifices. ASME Code, Section Xl, pump testing will verify that the

orifices have not experienced loss of material to the extent of impacting the ability of a pump to

provide the required flow.

The applicant will enhance system testing of the ESF ventilation units to manage the effects of -

aging on the drain valves and drain piping from these units. During surveillance testing, a

visual inspection of the drain valves and drain piping will be accomplished.

The applicant will enhance system testing of the control room ventilation units and fuel handling

exhaust unit to manage the effects of aging on the drain valves and drain piping from these - '-'-

units. During surveillance testing, a visual inspection of the drain valves and drain piping will be

accomplished.

Testing requirements include periodically starting the security diesel and operating it in

accordance with the manufacturer's recommendations. The applicant credited system testing

with managing fouling and the loss of material for the security diesel jacket water heat

exchangers and lubricating oil heat exchanger tubes. Since periodic engine testing and

inspections are performed on the security diesel, system testing is also credited for managing

the loss of material for the buried fuel oil storage tank, pipe, tubing and fittings, starting air

components, and exhaust gas components. Fuel oil level indication and periodic pressure

testing with use of the spectacle flange manage the aging effects on the buried fuel oil storage

tank. During engine operation, monitoring engine parameters and performing visual '

inspections manage the aging effects by verifying the pressure boundary of engine

components. In addition, the applicant performs 6-month and annual inspections on the '

security diesel to manage the aging effects on security diesel passive mechanical components.

The letdown orifices reduce the pressure in the letdown line from RCS pressure to the lower

pressure allowed for the demineralizers and other CVCS components. Normal plant operation

will verify the ability of the letdown orifices to control flow. The applicant records CVCS letdown

flow continuously on the plant process computer.

System testing includes monitoring the components during normal plant operation. For the

main steam system, this monitoring manages the aging effect of loss of material from the mainsteamflow restrictors. Changes in the flow reading would detect a material loss from the

internal surface of the flow restrictors significant enough to impact its flow control function. For

the blowdown system, the applicant credited this monitoring with ensuring that the restricting

orifices perform their flow control (pressure breakdown) function and manage the aging effect

of loss of material from erosion for the internal surfaces of the orifices.

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Finally, the applicant monitors the SFP water level and records it once per shift. Monitoring the

SFP level allows early detection of leakage through the SFP liner. This program manages the

aging effect of loss of material and cracking for the SFP liner.

By letter dated May 6, 2004, the staff forwarded to the applicant an RAI stating that, in

LRA Table 3.3.2-9, the applicant credited the System Testing Program with managing loss of

material for stainless steel fittings and stainless steel/carbon steel piping in a soil environment.

However, the System Testing Program does not define fitting or pipe condition, or the

approximate rate of degradation as recommended in GALL AMPs XI.M28, 'Buried Piping and

Tanks Surveillance," and XI.M34, "Buried Piping and Tanks Inspection," for buried

fittings/piping. Therefore, in RAI 3.3.2.1.9-1 the staff asked the applicant to either justify the

exclusion of the buried piping/fittings condition assessment from the System Testing Program

or to revise its LRA accordingly (see Section 3.3.2.3.9 of this SER for the response to and staff

evaluation of RAI 3.3.2.1.9-1).

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The selection of parameters monitored and the frequency with which they are

evaluated are consistent with the goal of detecting aging effects before loss of function occurs.

The applicant identified the need to enhance the System Testing Program to inspect centrifugal charging pump minimum flow orifices and to address the verification of pressure boundary integrity in various drain systems. The staff finds that the Detection of Aging Effects program element is acceptable.

Monitoring and Trending. The applicant stated, in Section B.1.37 of Appendix B to the LRA, that it performs the surveillance and monitoring activities associated with this program on a

specific frequency, as listed in the Site Surveillance Tracking Database, and documents the

results of these activities. The program includes various frequencies, depending upon the

specific component or system tested.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect

aging effects before a loss of intended function occurs. On this basis, the staff finds that the

Monitoring and Trending program element is acceptable.

Acceptance Criteria. The applicant stated, in Section B.1.37 of Appendix B to the LRA, that the

governing procedures provide the acceptance criteria and guidelines for the surveillances and

normal log readings. Acceptance criteria are tailored for each individual system or component test.

The staff reviewed a sample of plant testing procedures and confirmed that this program element satisfies the criteria defined in Appendix A.1 to the SRP-LR. The staff finds that, under

the plant Corrective Action Program, the applicant will find deficiencies unacceptable, when

discovered during inspections, and implement corrective measures. On this basis, the staff

finds that the Acceptance Criteria program element is acceptable.

Operating Experience. The applicant stated, in Section B.1.37 of Appendix B to the LRA, that a

review of CRs and interviews with the system managers, related to the various tests and

inspections that constitute the System Testing Program, found that testing procedure issues

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have been identified and corrected. Although typical component problems have been identified,

system testing has not identified abing-related problems for monitored components.

The staff noted that plant operating experience with respect to system testing is extensive. The

staff reviewed the applicant's documentation of operating experience for the System Testing

Program and finds that it is not specific to the aging effects of concern or the components

addressed. However, the program has identified and corrected comparable component

problems, suggesting that it will be effective if aging effects are observed.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the System Testing Program adequately

manages the aging effects that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.40 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the System Testing Program and stated that the program encompasses a number of

miscellaneous system and component testing activities credited for managing the effects of

aging. These activities typically include surveillance activities required by the technical

specifications or normal monitoring of plant operation (i.e., plant log readings or other normal

monitoring techniques). In general, the applicant conducts these activities on a periodic basis

(surveillances) or routinely (logs) during plant operation. The activities verify the continuing

capability of safety-related systems and components to meet established performance

requirements. This program requires enhancements that will be implemented before the period

of extended operation. The enhancements are part of Commitment #26 in Appendix A of this

SER.

The staff reviewed 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 the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs will be maintained consistent with the CLB for the period of extended

operation, as required by1 0 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).

3.0.3.3.14 System Walkdown

Summarv of Technical Information in the APplication

Section B.1.38, "System Walkdown," of the LRA describes the applicant's System Walkdown

Program. In the LRA, the applicant credited this plant-specific program with (1) managing the

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, (2)

managing loss of material of external carbon steel surfaces, and (3) managing loss of

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mechanical closure integrity for bolted closures that may be exposed to borated water leakage. The applicant also credited the program with detecting leakage and spray from liquid-filled low-energy systems before such leakage can prevent the satisfactory accomplishment of safety functions.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section

B.1.38 of Appendix B to the LRA, regarding the applicant's demonstration of the System Walkdown Program to ensure that it will adequately manage the effects of aging, as discussed

above, so that the intended functions of SCs 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 Table

A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's

management of aging effects through the effective incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated in

Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scoge of Program. The applicant stated, in Section B.1.38 of Appendix B to the LRA, that, it

will enhance this program element to include balance-of-plant systems such as fire protection and security diesel and nonsafety-related components affecting safety-related systems.

The staff confirmed that the Scope of Program element satisfies the criteria defined in Appendix A.1 to 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, in Section B.1.38 of Appendix B to the LRA, that for

carbon steel components with coatings, the System Walkdown Program manages the loss of

material due to corrosion of the carbon steel surfaces by ensuring that the coating integrity is

maintained.

The staff confirmed that the program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The System Walkdown Program activities will identify component aging effect

and prevent failures of components that might be caused by aging effects. On this basis, the

staff finds that the Preventive Actions program element is acceptable.

Parameters Monitored or Inspected. The applicant stated, in Section B. 1.38 of Appendix B to

the LRA, 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 walkdowns

include condition and placement of coatings, evidence of corrosion, and indications of leakage. The applicant also stated that it will enhance this program element to ensure that evidence of

corrosion is adequately monitored.

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The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to -

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

program element is acceptable. ,

Detection of Aging Effects. The applicant stated, in Section B.1.38 of Appendix B to the LRA,

that it conducts a general visual inspection on readily accessible system and component -

surfaces during walkdowns. It credited the program with managing the loss of material for

external and internal carbon steel surfaces, loss of mechanical closure integrity for bolted

closures that may be exposed to borated water leakage, loss of material (including that caused

by selective leaching) for copper alloy and cast iron surfaces, and cracking of stainless steel

surfaces.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The applicant conducts walkdowns, using a frequency and sample size based on

operating experience, to detect the presence and extent of aging effects. By letter dated

May 26, 2004, in related RAI 3.3.2.1.11-3, the staff asked the applicant to explain how the

System Walkdown Program will detect the loss of material on the internal surfaces of the

components subject to an AMR that meet the criterion of 10 CFR 54.4(a)(2), or on those

nonsafety related components that affect the safety related function of a system within the

scope of license renewal (see Section 3.3.2.3.11 of this SER for the response to and staff

evaluation of RAI 3.3.2.1.11-3). The staff finds that the Detection of Aging Effects program

element is acceptable.

Monitoring and Trending. The applicant stated, in Section B.1.38 of Appendix B to the LRA,

that quarterly walkdown reports document the observations.

During the audit, the staff asked whether the walkdowns are performed quarterly or merely

documented quarterly. The applicant responded that it performs the walkdowns quarterly and

provided documentation of this requirement.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The respective plant system managers define the scope of the walkdowns. The.

program requires written reports, and the Corrective Action Program documents discrepancies.

On this basis, the staff finds that the Monitoring and Trending program element is acceptable.

AcceDtance Criteria. The applicant stated, in Section B.1.38 of Appendix B to the LRA, that

walkdown reports document safety or operability concerns and provide an overall assessment

of the system condition, based on observations. The reports summarize specific needs for

improvement and followup actions. CRs are generated, as required. The applicant also stated

that it will enhance this program element to ensure the adequate-detection of aging effects.-

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The staff finds that the applicant will consider any deficiencies to be unacceptable

and implement corrective measures. On this basis, the staff finds that the Acceptance Criteria

program element is acceptable.

Operating Experience. The applicant stated, in Section B.1.38 of Appendix B to the LRA, that

CRs document indications of component aging identified during system walkdowns.

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Walkdowns have identified conditions such as boric acid leakage at a valve flange, corrosion on

anchor bolts, and tank surface pitting.

The applicant stated in the LRA that the CRs show that not only have aging effects like

corrosion been noted and corrected, but aging management conditions that promote these

aging effects have been noted and corrected as well. Among the conditions noted during a

walkdown of the control room ventilation system in 1999, corrosion of the inside of the duct

work was believed to be caused by clogged drains, which was in turn caused by inadequate surveillance activities and insufficient housekeeping. The control room ventilation system was

cleaned monthly for 6 months until the condition of the system was such that a return to normal

housekeeping was considered adequate.

The staff reviewed the applicant's documents and concludes that the applicant has identified

operating experience for the System Walkdown Program and performed corrective actions,

where needed, as a result.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the System Walkdown Program adequately

manages the aging effects that have been observed at the applicant's plant.

UFSAR Sugplement

In Section A.2.1.41 of Appendix A to the LRA, the applicant provided the UFSAR Supplement for the System Walkdown Program and stated that the program conducts inspections to

manage the loss of material, the 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 applicant stated that it will implement the required program enhancements before the

period of extended operation. The enhancements are part of Commitment #27 in Appendix A

of this SER.

The staff reviewed 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 the applicant has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs 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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3.0.3.3.15 Wall Thinning Monitoring

Summary of Technical Information in the Application

Section B.1.39, 'Wall Thinning Monitoring,' of the LRA describes the applicant's Wall Thinning

Monitoring Program. In the LRA, the applicant credited this new, plant-specific program with

managing the aging effects for loss of material to ensure 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 Section

B.1.39 of Appendix B to the LRA, regarding the applicant's demonstration of the Wall Thinning

Monitoring Program to ensure that it will adequately. manage the effects of aging, as discussed

above, so that the intended functions of SCs 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

Table A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's

management of aging effects through the effective incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated in

Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scope of Program. The applicant stated, in Section B.1.39 of Appendix B to the LRA, that the

program encompasses wall thinning monitoring inspections for carbon steel piping and valves

in the containment isolation system and AFW system to ensure that piping wall thickness is

above the minimum required.

The staff confirmed that the Scope of Program element satisfies the criteria defined in Appendix

A.1 to 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, in Section B.1.39 of Appendix B to the LRA, that the

Wall Thinning Monitoring Program is an inspection program and will include no actions to

prevent or mitigate degradation caused by aging.

The staff confirmed that the program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The staff did not identify the need for preventive actions for the Wall Thinning

Monitoring Program because it is a condition monitoring program.

Parameters Monitored or Inspected. The applicant stated, in Section B.1.39 of Appendix B to -

the LRA, that it will perform nondestructive examinations on susceptible components to

determine wall thickness.

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The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. 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 program element is acceptable.

Detection of Aging Effects. The applicant stated, in Section B.1.39 of Appendix B to the LRA,

that this program manages the aging effect of loss of material. The applicant will determine an

appropriate sample size based on operating experience before these inspection activities occur.

It will design the extent and schedule of the examinations prescribed by the program to ensure

that aging effects will be discovered and repaired before the loss of intended function.

Inspections will be performed periodically at a frequency to be determined before

implementation. The frequency of inspections will depend upon results of previous inspections, the calculated rate of material loss, and industry and plant operating experience. In addition,

the applicant credited this program with managing the aging effects of loss of material from the

internal surfaces of the containment penetrations' carbon steel components and loss of material

on the internal surfaces of the AFW system carbon steel components.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The applicant stated that it will perform the inspections periodically at a frequency

to be determined before the end of the initial 40-year license term. The frequency of

inspections will depend upon the results of previous inspections, the calculated rate of material

loss, and industry and plant operating experience. On this basis, the staff finds the Detection of

Aging Effects program element to be acceptable.

Monitoring and Trending. The applicant stated, in Section B.1.39 of Appendix B to the LRA,

that it will trend wall thickness and project it to the next inspection. It will take corrective actions

if the projections indicate that the acceptance criteria may not be met at the next inspection.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect

aging effects before the loss of intended function occurs. On this basis, the staff finds that the

Monitoring and Trending program element is acceptable.

Acceptance Criteria. The applicant stated, in Section B.1.39 of Appendix B to the LRA, 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 to

the SRP-LR. The staff finds that the applicant will consider any wall thickness values that are

projected to fall below the design code minimum to be unacceptable and implement corrective

measures. The staff concludes that this acceptance criterion is adequate to demonstrate that a

loss of material because of wall thinning will be managed for the period of extended operation and that correction actions will be implemented for any wall thickness values projected to fall

below the minimum allowable. On this basis, the staff finds that the Acceptance Criteria

program element is acceptable.

Operating Experience. The applicant stated, in Section B.1.39 of Appendix B to the LRA, that

the Wall Thinning Monitoring Program is a new program for which there is no operating

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experience. It will consider industry and plant-operating experience in the development of this

program.

The Operating Experience program element criteria in Appendix A.I to the SRP-LR states that

operating experience should provide objective evidence to support the conclusion that the

program will adequately manage the effects of aging so that the SC intended functions will be

maintained during the period of extended operation. -

The staff observed that ultrasonic wall thickness examinations are consistent with industry

standards, and the applicant 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 this AMP 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

reasonable 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 and discussions with the applicant's technical staff, the staff

concludes that the Wall Thinning Monitoring Program will adequately manage the aging effects

that have been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.42 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Wall Thinning Monitoring Program and stated that the program will manage the loss of

material of carbon steel piping and valves in the containment isolation and AFW systems. The

applicant will perform inspections to ensure that wall thickness is above the minimum required

in order to avoid failures. Finally, the applicant will implement the Wall Thinning Monitoring

Program before the period of extended operation. This is Commitment #28 in Appendix A of

this SER.

The staff reviewed 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 the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs 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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3.0.3.3.16 Water Chemistry Control-Auxiliary Systems Water Chemistry Control

Summary of Technical Information in the Application

Section B.1.40.3, 'Water Chemistry Control-Auxiliary Systems Water Chemistry Control," of

the LRA describes the applicant's Water Chemistry Control-Auxiliary Systems Water

Chemistry Control Program. In the LRA, the applicant credited this plant-specific program with

managing the 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 Section

B.1.40.3 of Appendix B to the LRA, regarding the applicant's demonstration of the Water

Chemistry Control-Auxiliary Systems Water Chemistry Control Program to ensure that it will

adequately manage the effects of aging, as discussed above, so that the intended functions of

SCs will be maintained consistent with the CLB throughout the period of extended operation.

The staff reviewed the Water Chemistry Control-Auxiliary Systems Water Chemistry Control

Program against the AMP elements found in Table A.1-1 and Section A.1.2.3 of Appendix A to the SRP-LR and focused on the program's management of aging effects through the effective

incorporation of the 10 program elements.

The applicant indicated that the site-controlled Quality Assurance Program, evaluated in

Section 3.0.4 of this SER, includes the corrective actions, confirmation process, and

administrative controls. The following paragraphs discuss the remaining seven elements.

Scope of Program. The applicant stated, in Section B.1.40.3 of Appendix B to the LRA, that the

program encompasses sampling activities and analyses of the demineralized water supply - penetrations and nonsafety-related components affecting safety-related systems, control room

ventilation liquid chiller components, glycol/ice condenser penetrations, glycol/ice condenser

nonsafety-related components affecting safety-related systems, primary water supply to

pressurizer relief tank penetrations, primary water system nonsafety-related components affecting safety-related systems, EDG jacket cooling water, and security diesel jacket cooling water.

The staff confirmed that the Scope of Program element satisfies the criteria defined in Appendix A.1 to 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, in Section B.1.40.3 of Appendix B to the LRA, that

this program monitors and controls relevant conditions such as dissolved oxygen,, conductivity, and corrosion inhibitor concentrations to manage loss of material and fouling, as applicable. These corrosive contaminants are either removed, their concentrations minimized, or

treatments are provided to limit their corrosive effects.

During the audit, the applicant provided clarification on the parameters to be monitored and

their ability prevent or mitigate the aging effects. Where applicable, system chemistry

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monitoring uses the principles for chemical treatment and a typical (chemistry) monitoring

program presented in EPRI TR-107396. Dissolved oxygen is included as a diagnostic

parameter because it can increase corrosion. The demineralized water application includes it

as a control treatment parameter: Conductivity is included as a diagnostic parameter because

it is an indirect measurement of the concentration of chemical treatment (used to minimize

corrosion or fouling). Corrosion inhibitor is monitored for direct measurement of the treatment

control concentration used for corrosion control. Because pH has a direct impact on corrosion

rate and might be an indicator of microbiological activity in the system, it is included as a

treatment control parameter. Iron and copper are included as diagnostic parameters because

accumulation of corrosion products is an indirect indication of corrosion. -Hardness is monitored

to provide indication of the formation of mineral scales., Nitrate is monitored and included as a

diagnostic for an indication of an increase in microbiologic activity. Glycol weight percentage

concentration is monitored to ensure that the range specified in Section 5.3.5.12.3 of the

UFSAR is maintained.

The staff confirmed that the Preventive Actions program element satisfies the criteria defined in

Appendix A.1 to the SRP-LR. On the basis of its audit of the implementation procedures and

review of the program basis documents, the staff finds that the Preventive Actions program

element is acceptable because it identifies and describes the activities for managing aging

effects.

Parameters Monitored or Inspected. The applicant stated, in Section B.1.40.3 of Appendix B to

the LRA, that the program monitors specific parameters such as dissolved oxygen, conductivity,-

and corrosion inhibitor concentrations. It monitors other typical parameters, including pH, iron,

copper, hardness, and nitrite. The specific parameters monitored vary depending on the

system.

During the audit, the applicant stated that the parameters monitored and the established

chemistry limits in the auxiliary cooling systems are based on a strategic plan that was

developed according to the systems' materials of construction and currently approved chemical

treatments. The program monitors corrosion inhibitor concentrations to ensure adequate

protection of the system materials from corrosion. Other parameters are monitored to assess

the rates of corrosion and stability of the system. In the case of primary makeup systems,

parameters and limits are based on practices developed by EPRI for primary water chemistry.

The staff confirmed that this program element satisfies the criteria defined in Appendix A.1 to

the SRP-LR. The component inspections and water chemistry monitoring activities are

intended to 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 Agin6 Effects. The applicant stated, in Section B.1.40.3 of Appendix B to the LRA,

that the Water Chemistry Control-Auxiliary Systems Water Chemistry Control Program is a

mitigation program and does not provide for detection of aging effects, such as loss of material

and cracking. This applicant credited this program with managing the aging effects of the

following: loss of material for the demineralized water, glycoVice condenser, and primary water

containment penetrations; loss of material (including that caused by selective leaching) and

fouling in the EDG cooling water system; loss of material (including that caused by selective

leaching) and fouling from the internal wetted surfaces of the control room ventilation liquid

chiller components; loss of material (including that caused by selective leaching) for the security

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diesel engine cooling water; and loss of material (including that caused by selective leaching)

for the demineralized water, ice condenser, and primary water nonsafety-related components

affecting safety-related systems.

The staff agrees that this is a mitigation program and as such does not detect aging effects,

such as loss of material and cracking. Therefore, the staff concluded that this program element

satisfies the criteria defined in Appendix A.1 to the SRP-LR. On this basis, the staff finds that

the Detection of Aging Effects program element is acceptable.

Monitoring and Trending. The applicant stated, in Section B.1.40.3 of Appendix B to the LRA,

that it implements the program through various plant procedures. The applicable procedures

identify the sampling schedule, the critical parameters, and the location of the sample points.

The applicant monitors the parameters and takes corrective actions if the parameters are

outside the acceptable range.

The staff reviewed several implementing procedures and determined that the applicant defined

the sampling schedule, critical parameters, and location of the sample points. The staff

confirmed that this program element satisfies the criteria defined in Appendix A.1 to the

SRP-LR. Trending of the inspection results will enhance the applicant's ability to detect aging

effects before loss of intended function occurs. On this basis, the staff finds that the Monitoring

and Trending program element is acceptable.

Acceptance Criteria. The applicant stated, in Section B.1.40.3 of Appendix B to the LRA, that

site procedures for this program include the acceptance criteria, which are established based

on the sampled parameter, the sample location, and the plant operating conditions. The

applicant established these criteria based on equipment specification requirements, EPRI

guidelines, or CNP-specific experience.

The staff reviewed several plant procedures and verified that the program includes a

methodology for analyzing the results against specific numerical acceptance criteria. The staff

confirmed that this program element satisfies the criteria defined in Appendix A.1 to the

SRP-LR. The staff finds that the applicant will consider any inspection results that indicate

component degradation or any chemistry parameters that fall outside those contained in

applicable industry and manufacturers' guidelines and implement corrective measures. On this

basis, the staff finds that the Acceptance Criteria program element is acceptable.

Operating ExDerience. The applicant stated, in Section B.1.40.3 of Appendix B to the LRA, that

a review of representative CRs relevant to the program shows that the program identifies

out-of-specification values and corrects them before they lead to equipment degradation. For

example, the program identified and corrected excessive sodium in the borated water

inventories, nitrites below the minimum limit for the diesel jacket cooling water, and low pH in

the alternate heating boiler.

During the audit, the staff interviewed applicant personnel concerning the operating experience

of this existing program to validate the AMP statements. The plant records confirm that the

program has effectively identified water chemistry parameters and taken corrective actions.

Based on its review, the staff concludes that the operating experience of this program

demonstrates that it is an effective tool for mitigating the aging effects of loss of material and

cracking.

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On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the Water Chemistry Control-Auxiliary

Systems Water Chemistry Control Program adequately manages the aging effects that have

been observed at the applicant's plant.

UFSAR Supplement

In Section A.2.1.45 of Appendix A to the LRA, the applicant provided the UFSAR Supplement

for the Water Chemistry Control-Auxiliary Systems Water Chemistry Control Program.' It

stated that the program manages loss of material and fouling, as applicable, of components

within the scope of license renewal that are exposed to treated water environments. The

program implements sampling activities and analyses to monitor and control relevant chemistry

conditions of these environments.

The staff reviewed 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 the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

functions of SCs 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).

3.0.3.3.17 Water Chemistry Control-Chemistry One-Time Inspection

Summary of Technical Information in the Application

Section B.1.41, 'Water Chemistry Control-Chemistry One-Time Inspection," of the LRA

presents the applicant's program to evaluate the effectiveness of water chemistry programs.

The applicant stated that this plant-specific program will be comparable to GALL AMP XL.M32,

"One-Time Inspection," and consistent with its general elements, but smaller in scope. The

program performs inspections that will verify the effectiveness of water chemistry control ' '

programs and ensure that aging effects are effectively managed during the period of extended

operation. The applicant stated that qualified personnel will perform combinations'of NDE

(including visual, ultrasonic, and surface techniques) by following procedures consistent with

ASME Code,-Section XI, and Appendix B to 10 CFR Part 50. -Followtip of unacceptable

inspection findings may include expansion of the inspection sample size and locations.

Staff Evaluation

The GALL Report recommends use of GALL AMP XL.M32 to verify the effectiveness of an AMP

and confirm the absence of an aging effect. For example, for SCs that rely on an AMP such as

a water chemistry control program, GALL AMP XL.M32 verifies the effectiveness of the AMP by

confirming that unacceptable degradation is not occurring and that the intended function of a

component will be maintained during the period of extended operation. One-time inspection

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addresses cases where either (1) an aging effect is not expected to occur but there are

insufficient data to rule it out, or (2) an aging effect is expected to progress very slowly. Onetime inspection can provide assurance that aging is either not occurring, or the aging effect is

occurring very slowly so as not to affect the intended function of the structure and component. When a one-time inspection reveals evidence of an aging effect, the evaluation of the

inspection results would identify appropriate corrective actions, which may include followup inspections.

In a letter dated May 19, 2004, the staff requested in RAI B.1.41-1 that the applicant provide details about key program elements that clarify the difference between the applicant's program and GALL AMP XI.M32. In a letter dated August 11, 2004, the applicant stated that two CNP

AMPs contain GALL AMP XI.M32; the Small Bore Piping Program, described in LRA Section

B.1.30, and the Water Chemistry Control-Chemistry One-Time Inspection Program, described

in LRA Section B.1.41. According to the applicant, these two programs comprise all of the

elements of GALL AMP XI.M32, and there are no resultant differences between GALL AMP

XI.M32 and the two programs listed in the LRA. The staff concluded that the applicant's Water

Chemistry Control-Chemistry One-Time Inspection Program is consistent with the GALL AMP

XLI.M32 for the components included within its scope, and that the only difference is the use of a

separate program to address small bore piping.

The applicant stated that the Water Chemistry control-Chemistry One-Time Inspection Program is a new program that will be developed and initiated prior to the period of extended

operation. This is Commitment #30 in Appendix A of this SER. The program will address

components for which a water chemistry control programs have been credited as an AMP in the

LRA Section 3 AMR results tables. In addition, the program will focus on materials and

environments for which the GALL Report specifies the need to verify effectiveness of the water

chemistry control programs. The elements of the GALL AMP XI.M32 include (1) determination

of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience, (2) identification of the inspection locations in the

system or component based on the aging effect, (3) determination of the examination

technique, including acceptance criteria that would be effective in managing the aging effect for

which the component is examined, and (4) evaluation of the need for follow-up examinations to

monitor the progression of any aging degradation.

The applicant stated that examples include carbon steel components in applicable steam and

power conversion systems. The program will include components in stagnant or low-flow areas

that are most susceptible to aging. In a public meeting on September 1, 2004, documented as

RAI B.1.41-2 in a letter dated September 29, 2004, the staff asked the applicant to provide a list

of components, material types, environments, and aging effects that will be inspected to verify the effectiveness of the Water Chemistry Control-Chemistry One-Time Inspection Program and to justify that these components provide an adequate sample size to verify the

effectiveness of the program for each aging effect managed.

In a response dated October 18, 2004, the applicant confirmed that its program will include all

combinations identified by the GALL Report for the aging management of PWR components using water chemistry control and the One-Time Inspection Program. The staff compared the

applicant's AMR with the one-time inspections recommended in the GALL Report to verify the

effectiveness of water chemistry control in managing aging. The staff confirmed that these

structures and components are either included in the applicant's One-Time Inspection Program

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or another aging management program that includes periodic inspection (i.e., Diesel Fuel,

Monitoring Program, Boric Acid Corrosion Prevention Program). For example, the GALL ' '-'

Report recommends water chemistry control and one-time inspection for general, pitting, and

crevice corrosion of steam and power conversion system components such as piping and

fittings, valve bodies and bonnets, pump casings, tanks, tubes, tubesheets, channel head, and

shells. The staff confirmed that the applicant's AMR includes these items and identifies water

chemistry and one-time inspection as the AMPs.

In the October.18, 2004 letter, the applicant also identified additional material and environment "

combinations, beyond those listed in the GALL Report, that it will include in the One-Time

Inspection Program.> Other RAI responses (RAls 3.2-11, 3.2-12,.3.3.2.1.9-4, 3.3.2.1.9-6, 3.4-7,;

3.4-8, 3.4-10, 3.4-11, and 3.3.2.1.11-1) originally documented these combinations. These

additional combinations include the loss of material of a copper alloy heat exchanger tubes in

treated water; loss of material of carbon steel in treated water and stainless steel in borated

water in the ESF system; copper alloy security diesel and jacket water coolers; loss of material

and fouling of copper alloy tubes in the AFW system; loss of material and cracking of stainless

steel and loss of material of carbon/alloy steel in treated water and steam; and copper alloy,

carbon steel, and stainless steel components exposed to raw and untreated water. The staff

finds the scope of the program acceptable because it includes the items identified in the GALL

Report,- as well as additional items for which a one-time inspection is appropriate to verify the

effectiveness of water chemistry control.

Regarding the actual sample population and size for the inspections, the applicant stated in the

October 18, 2004 response that the list of specific components and locations is not available

because the CNP Chemistry One-Time Inspection Program is new. The applicant confirmed

that the sample population (and size) will be based on material, environment, time in service,

aging effects, and operating experience, as discussed in GALL AMP XL.M32. Also consistent

with the GALL Report, the applicant stated in the LRA that qualified personnel will perform - - '

combinations of NDE (including visual, ultrasonic, and surface techniques) following procedures

consistent with the ASME Code, Section Xl and Appendix B to 10 CFR Part 50. Follow-up of

unacceptable inspection findings may include expansion of the inspection sample size and -

locations. When the program details are determined, the acceptance criteria will be specified

based on the relevant conditions of degradation. The staff finds these elements of the program

acceptable because they are consistent with the GALL Report.

UFSAR Supplement

In Section A.2.1.45 of Appendix A to the LRA, .the applicant provided its UFSAR Supplement for

the Water Chemistry Control-Chemistry One-Time Inspection Program. The staff reviewed

the UFSAR Supplement and finds that the summary description contains a sufficient level of

information to satisfy 10 CFR 54.21 (d) and therefore is acceptable.

Conclusion

The staff reviewed the available information on the applicant's program and finds that the

program is consistent with the GALL Report. Certain details, such as the exact sample size

and the inspection method, will be determined in when the plan is implemented. The one

difference between this program and the GALL AMP is the exclusion of small bore piping, which

.is covered by a separate program. The staff also reviewed the UFSAR Supplement for this

3-143
AMP and finds that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

Therefore, based on its review, the staff finds that the applicant has shown that the effects of

aging will be adequately managed by the Water Chemistry Control - Chemistry One-Time

Inspection program so that the intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

Pursuant to 10 CFR 54.21 (a)(3), a license renewal applicant must demonstrate that it will

adequately manage the effects of aging on SCs subject to an AMR so that their intended

functions will be maintained consistent with the CLB for the period of extended operation. The

SRP-LR, BTP RLSB-1, uAging Management Review-Generic," describes 10 attributes of an

acceptable AMP. Three of these 10 attributes are associated with the QA activities of

corrective action, confirmation processes, and administrative controls. Table A.1-1, "Elements

of an Aging Management Program for License Renewal," of BTP RLSB-1 provides the following description of these quality attributes:

* Corrective actions, including root cause determination and prevention of recurrence, should be timely.

* The confirmation process should ensure that preventive actions are adequate and that

appropriate corrective actions have been completed and are effective.

* Administrative controls should provide a formal review and approval process.

The SRP-LR, BTP IQMB-1, "Quality Assurance for Aging Management Programs," notes that

those aspects of the AMP that affect the quality of safety-related SSCs are subject to the QA

requirements of Appendix B to 10 CFR Part 50. Additionally, for nonsafety-related SCs subject to an AMR, the applicant may use the existing Quality Assurance Program under Appendix B to

10 CFR Part 50 to address the program elements of Corrective Actions, Confirmation Process, and Administrative Controls. BTP IQMB-1 provides the following guidance with regard to the

QA attributes of AMPs:

* Safety-related SCs are subject to the requirements under Appendix B to

10 CFR Part 50, which adequately address all quality-related aspects of an AMP

consistent with the CLB of the facility for the period of extended operation.

* -For nonsafety-related SCs that are subject to an AMR for license renewal, an applicant has an option to expand the scope of its Quality Assurance Program under Appendix B

to 10 CFR Part 50 to include these SCs to address corrective actions, the confirmation

process, and administrative controls for aging management during the period of

extended operation. In this case, the applicant should document such a commitment in

the FSAR Supplement in accordance with 10 CFR 54.21 (d).

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3.0.4.1 Summary of Technical Information in the Application

The applicant described the quality attributes of AMPs in Section B.0.3, UCNP Corrective

Actions, Confirmation Process, and Administrative Controls," of the LRA.

Corrective Actions The applicant stated that it implements CNP QA procedures, review and

approval processes, and administrative controls in accordance with the requirements of -

Appendix B to 10 CFR Part 50.- Conditions adverse to quality (i.e., failures, malfunctions,

deviations, defective material and equipment, and nonconformances) are promptly identified

and corrected. In the case of significant conditions adverse to quality, it implements measures

to ensure that the cause of the nonconformance is determined and that corrective action is

taken to preclude repetition. The applicant stated that it accomplishes corrective actions for

both safety related and nonsafety related SCs through the existing Corrective Action Program.

Confirmation Process The applicant stated that the Corrective Action Program includes the

requirement that measures be taken to preclude repetition of significant conditions adverse to

quality. These measures include actions to verify the effective implementation of proposed

corrective actions. Corrective actions for both safety related and nonsafety related SCs are

accomplished through the existing Corrective Action Program. The confirmation process is part

of the Corrective Action Program. For significant conditions adverse to quality, the process

includes reviews to assure that (1) proposed actions are adequate, (2) open corrective actions

are tracked and reported, and (3) corrective action effectiveness is reviewed for root cause

determination.

Administrative Controls The applicant accomplishes administrative control for both

safety-related and nonsafety related SCs in accordance with the existing Document Control

Program based on the quality assurance program description (QAPD).

3.0.4.2 Staff Evaluation

RAI2.1-6

The NRC staff reviewed the applicant's QA controls for AMPs as described in the LRA to

assure that the aging management activities are consistent with the staff's guidance described

in Section A.2, "Quality Assurance for Aging Management Programs (BTP IQMB-1)," of the

SRP-LR regarding quality assurance attributes of AMPs. Based on the staff's evaluation, the

descriptions and applicability of the plant-specific AMPs and their associated quality attributes

provided in Section B.0.3 of the LRA are consistent with the staff's position regarding quality

assurance for aging management. In particular, the applicant noted that its QA Program

provides elements of Corrective Actions, Confirmation Process, and Administrative Controls for

both safety related and nonsafety related SSCs. However, the applicant did not describe the

use of the QA Program and its associated attributes in Appendix A to the LRA. Therefore, in

RAI 2.1-6, the staff requested the applicant to clarify its position with regard to the quality

attributes of AMPs in Appendix A to the LRA. Specifically, consistent with BTP IQMB-1, the

applicant should either document a commitment to expand the scope of its program under

Appendix B to 10 CFR Part 50 to include nonsafety-related SCs subject to an AMR to address

the AMP quality attributes during the period of extended operation or propose an alternative

means to address this issue.

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The applicant responded to RAI 2.1-6 by letter dated May 7, 2004. In this response, the

applicant stated that it will revise the UFSAR Supplement in Appendix A to the LRA to clarify its

position on the quality attributes of AMPs. The applicant will add the following paragraph to

LRA Section A.2.1, "Aging Management Programs and Activities.:

The CNP Quality Assurance Program Description implements the requirements of 10 CFR 50, Appendix B, and is consistent with the summary in Section A.2 of

NUREG-1 800, Standard Review Plan for the Review of license Renewal

Applications for Nuclear Power Plants. published July 2001. The Quality Assurance Program Description includes the elements of corrective action,

confirmation process, and administrative controls, and is applicable to the safety related and non-safety related structures, systems, and components that are

within the scope of license renewal.

The staff determined that application of the QAPD to both safety related and nonsafety related

SSCs within the scope of license renewal is consistent with the staff position contained in BTP

IQMB-I. Therefore, on this basis, RAI 2.1-6 is resolved.

3.0.4.3 Conclusion

The staff finds that the QA attributes of the applicant's AMPs are consistent with

10 CFR 54.21(a)(3). Specifically, the applicant described the quality attributes of the programs and activities for managing the effects of aging for both safety-related and nonsafety-related SSCs within the scope of license renewal. It stated that the Quality Assurance Program under

Appendix B to 10 CFR Part 50 provides corrective actions, confirmation processes, and

administrative controls. Therefore, the staff concluded that the applicant adequately described

the quality attributes of its AMPs.

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 RCS components and component groups associated with the

following systems:

* reactor vessel and control rod drive mechanism (CRDM) pressure boundary * reactor vessel internals

* Class 1 piping, valves, and reactor coolant pumps (RCPs)

* pressurizer

* steam generators

3.1.1 Summary of Technical Information in the Application

In Section 3.1 of the LRA, the applicant provided the AMR results for the reactor vessel,

internals, RCS, pressurizer, and steam generator components and component types listed in

Tables 2.3.1-1 through 2.3.1-5 of the LRA. The applicant also listed the materials,

environments, aging effects requiring management (AERMs), and AMPs associated with each

system.

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In LRA Table 3.1.1, "Summary of Aging Management Programs for the Reactor Coolant

System Evaluated in Chapter IV of NUREG-1801," the applicant provided a summary

comparison of its AMRs with the AMRs evaluated in the GALL Report for the reactor vessel,

internals, RCS, pressurizer, and steam generator components and component types. In

Section 3.1.2.2 of the LRA, the applicant provided information concerning Table 3.11

components for which the GALL Report recommends further evaluation.

3.1.2 Staff Evaluation

The staff reviewed Section 3.1 of the LRA to understand the applicant's review process and to

determine whether the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the reactor vessel, internals, RCS, pressurizer, and

steam generator components that are within the scope of license renewal and subject to an

AMR 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 verify that

the material presented in the LRA was applicable and that the applicant identified the

appropriate GALL Report AMRs. Section 3.1.2.1 of this SER summarizes the staff's audit

findings.

The staff also audited and reviewed those AMRs that are consistent with the GALL Report and

for which further evaluation is recommended. The staff verified that the applicant's further,

evaluations are consistent with the acceptance criteria in Section 3.1.3.2 of the SRP-LR.

Section 3.1.2.2 of this SER summarizes this aspect of 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 the applicant identified all plausible

aging effects, and whether the aging effects listed are appropriate for-the combination of

materials and environments specified. Section 3.1.2.3 of this 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 RCS system components and component groups.

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.

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

Components Listed in the GALL Report

Component-,' Aging Effect/ -:,AMP in GALL - AMP in LRA, - Staff i'. -

- Group Mechanism, Report - i... Evaluation

RCPB (Item Cumulative fatigue TLAA, evaluated in TLAA Consistent with

Number 3.1.1-1) damage accordance with GALL, which

10 CFR 54.21(c) recommends further

evaluation (See

Section 3.1.2.2.1)

Steam generator Loss of material due Inservice Water Chemistry Consistent with

shell assembly to pitting and crevice Inspection; Water Control-Primary GALL, which

(Item Number corrosion Chemistry and Secondary recommends further

3.1.1-2) Water Chemistry evaluation (See Control Program Section 3.1.2.2.2) (B.1.40.1); Inservice

Inspection-ASME

Section Xl,

Subsection IWB, IWC, and IWO

Program (B.1.14); Steam Generator

Integrity Program

(B.1.31)

Pressure vessel Loss of fracture TLAA, evaluated in TLAA Consistent with

ferritic materials toughness due to accordance with GALL, which

that have a neutron irradiation Appendix G to recommends further

neutron fluence embrittlement 10 CFR Part 50 evaluation (See

greater than 10'7 and RG 1.99 Section 3.1.2.2.3)

n/cm2 (E >1 MeV)

(Item Number

3.1.1-4)

Reactor vessel Loss of fracture Reactor Vessel Reactor Consistent with

beltline shell and toughness due to Surveillance Surveillance GALL, which

welds (Item neutron irradiation Integrity Program recommends further

Number 3.1.1-5) embrittlement (B.1.26) evaluation (See

Section 3.1.2.2.3)

Westinghouse Loss of fracture Plant specific Reactor Vessel Consistent with

and B&W toughness due to Internals Plates, GALL, which

baffle/former bolts neutron irradiation Forgings, Welds, recommends further

(Item Number embrittlement and and Bolting evaluation (See

3.1.1-6) void swelling - Program (B.1.27) Section 3.1.2.2.3)

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Component -'Aging Efftct/I AMP in GALL-- AMP in LRA Staff

Group .. . Mechanism Report -.- _________ ... Evaluation,.

Small-bore RCS Crack initiation and Inservice Inservice Consistent with

and connected growth due to SCC, Inspection; Water Inspection-ASME GALL, which -

systems piping IGSCC, and thermal Chemistry; One- Section Xl, recommends further

(Item Number and mechanical Time Inspection Subsection IWB, evaluation (See

3.1.1-7) loading IWC, and IWD Section 3.1.2.2.4)

Program (B.1.14);

Water Chemistry

Control-Primary

and Secondary

Water Chemistry

Control Program

(B.1.40.1); Small

Bore Piping

Program (B.1.30). _

Vessel shell (Item Crack growth due to TLAA TLAA-Under Clad Consistent with

Number3.1.1-10) cyclic loading Cracking GALL, which -

recommends further

evaluation (See

Section 3.1.2.2.5)

Reactor internals Changes in dimension Plant specific Reactor Vessel Consistent with

(Item Number due to void swelling Internals Plates, GALL, which

3.1.1-11) Forgings, Welds, recommends further

and Bolting evaluation (See

Program (B.1.27); Section 3.1.2.2.6)

Reactor Vessel

Internals Cast

Austenitic Stainless

Steel Program

(B.1.28)

PWR core Crack initiation and Plant specific Water Chemistry Consistent with

support pads, growth due to SCC Control-Primary GALL, which

instrument tubes and/or PWSCC and Secondary recommends further

(bottom-head Water Chemistry evaluation (See

penetrations), Control Program Section 3.1.2.2.7)

pressurizer spray (B.1.40.1); Alloy

heads, and 600 Aging

nozzles for the Management

steam generator Program (B.1.1);

instruments and Inservice

drains (Item Inspection-ASME

Number 3.1.1-12) Section Xl,

Subsection IWB,

IWC, and IWD

Program (B.1.14);

Pressurizer

Examinations

Program (B.1.24)

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Component Aging Effect!' AMP in GALL AMPMP in LRA- :,Staff .;

Group.> Mechanism Report >;* .' Evaluation--'.

CASS RCS piping Crack initiation and Plant specific Water Chemistry Consistent with

(Item Number growth due to SCC Control-Primary GALL, which

3.1.1-13) and Secondary recommends further

Water Chemistry evaluation (See

Control Program Section 3.1.2.2.7)

(8.1.40.1);

Inservice

Inspection-ASME

Section Xl,

Subsection IWB,

IWC, and IWD

Program (B.1.14)

Pressurizer Crack initiation and Inservice Water Chemistry Consistent with

instrumentation growth due to PWSCC Inspection; Water Control-Primary GALL, which

penetrations and Chemistry and Secondary recommends further

heater sheaths Water Chemistry evaluation (See

and sleeves Control Program Section 3.1.2.2.7)

made of nickel- (B.1.40.1); Alloy

alloys (Item 600 Aging

Number 3.1.1-14) Management

Program (B.1.1);

Inservice

Inspection-ASME

Section Xl,

Subsection IWB,

IWC, and IWD

Program (B.1.14)

Westinghouse Crack initiation and Plant specific Reactor Vessel Consistent with

and B&W baffle growth due to SCC Internals Plates, GALL, which

former bolts (Item and IASCC Forgings, Welds, recommends further

Number 3.1.1-15) and Bolting evaluation (See

Program (B.1.27); Section 3.1.2.2.8)

Inservice

Inspection-ASME

Section Xl,

Subsection IWB,

IWC, and IWD

Program (8.1.14);

Water Chemistry

Control-Primary

and Secondary

Water Chemistry

Control Program

(B.1.40.1)

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Component -Aging'Effect,-,' AMP in GALL AMPinLRA -Staff

-Group ;.:.- 'Mechanism -: Report : - Evaluation

Westinghouse Loss of preload due to Plant specific' Reactor Vessel Consistent with

and B&W baffle stress relaxation Internals Plates, GALL, which

former bolts (Item Forgings, Welds, recommends further

Number 3.1.1-16) and Bolting evaluation (See

Program (B.1.27); Section 3.1.2.2.9)

Inservice

Inspection-ASME

Section XI,

Subsection IWB,

IWC, and IWD

Program (B.1.14)

Steam generator Loss of section Plant specific Not applicable Consistent with

feedwater - thickness'due to GALL, which

impingement erosion recommends further

plate and support evaluation (See.

(Item Number Section 3.1.2.2.10)

3.1.1-17)

Alloy 600 steam Crack initiation and Steam Generator Steam Generator Consistent with

generator tubes, growth due to Tubing Integrity; Integrity Program GALL, which

repair sleeves, PWSCC, ODSCC, Water Chemistry (B.1.31); Water recommends further

and plugs (Item and/or IGA; loss of Chemistry evaluation (See

Number 3.1.1-18) material due to Control-Primary Section 3.1.2.2.11)

wastage and pitting and Secondary

corrosion and fretting Water Chemistry

and wear; or Control Program

deformation due to (B.1.40.1); Inservice

corrosion at tube Inspection-ASME

support plate Section XI,

intersections Subsection IWB,

IWC, and IWD

Program (B.1.14)

Tube support Loss of section Plant specific Not applicable Consistent with

lattice bars made thickness due to FAC GALL, which

of carbon steel recommends further

(Item Number evaluation (See

3.1.1-19) Section 3.1.2.2.12)

Carbon steel tube Ligament cracking due Plant specific Not applicable Consistent with

support plate to corrosion GALL, which

(Item Number recommends further

3.1.1-20) evaluation (See

Section 3.1.2.2.13)

Steam generator Loss of material due (CE) Steam Not applicable Consistent with

feedwater inlet to FAC Generator GALL, which

ring and supports Feedwater Ring recommends further

(Item Number Inspection evaluation (See

3.1.1-21) Section 3.1.2.2.14)

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Component Aging Effectf ' ''AMP in GALL'. AMP int LRA - - Staff,

'Groupie * Mechanism-;,: Report - .,Evaluation .;

Reactor vessel Crack initiation and Reactor Head Inservice Consistent with

closure studs and growth due to SCC Closure Studs Inspection-ASME GALL, which

stud assembly and/or IGSCC Section Xl, recommends no

(Item Number Subsection IWB, further evaluation

3.1.1-22) IWC, and IWD (See Section

Program (B.1.14) 3.1.2.1)

CASS pump Loss of fracture Inservice Inservice Consistent with

casing and valve toughness due to Inspection Inspection-ASME GALL, which

body (Item thermal aging Section Xl, recommends no

Number 3.1.1-23) embrittlement Subsection IWB, further evaluation

IWC, and IWD (See Section

Program (B.1.14) 3.1.2.1)

CASS piping Loss of fracture Thermal Aging Cast Austenitic Consistent with

(Item Number toughness due to Embrittlement of Stainless Steel GALL, which

3.1.1-24) thermal aging CASS Evaluation Program recommends no

embrittlement (B.1.7); Inservice further evaluation

Inspection-ASME (See Section

Section Xl, 3.1.2.1)

Subsection IWB,

IWC, and IWD

Program (B.1.14);

Pressurizer

Examinations

Program (B.1.24)

BWR piping and Wall thinning due to Flow Accelerated Flow-Accelerated Consistent with

fittings; steam FAC Corrosion Corrosion Program GALL, which

generator (B.1.12); Chemistry recommends no

components (Item Control Program further evaluation

Number 3.1.1-25) (B.1.40) (See Section

3.1.2.1)

RCPB valve Loss of material due Bolting Integrity Inservice Consistent with

closure bolting, to wear; loss of Inspection-ASME GALL, which

manway and preload due to stress Section Xl, recommends no

holding bolting, relaxation; crack Subsection IWB, further evaluation

and closure initiation and growth IWC, and IWD (See Section

bolting in high- due to cyclic loading Program (B.1.14); 3.1.2.1)

pressure and and/or SCC Bolting and

high-temperature Torquing Activities

systems (Item Program (B.1.2);

Number 3.1.1-26) Boric Acid

Corrosion

Prevention Program

(B.1.4)

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Component Aging Effect AMP in GALL AMP.in 1 RA- Sta ;: - Group .-... v-.Mechanism -.. * .Report - - val uation

CRD nozzle (Item Crack initiation and Ni-Alloy Nozzles Inservice Consistent with

Number 3.1.1-35) growth due to PWSCC and Penetrations;.- Inspection-ASME GALL, which

Water Chemistry Section Xl, recommends no

Subsection IWB, further evaluation:

IWC, and IWD (See Section

Program (B.1.14); 3.1.2.1)

Water Chemistry

Control Program

(B.1.40); Control

Rod Drive

Mechanism and

Other Vessel Head

Penetration

Inspection Program

(B.1.9)

Reactor vessel Crack initiation and Inservice -- Inservice - Consistent with

nozzles safe ends growth due to cyclic Inspection; Water Inspection-ASME GALL, which

and CRD; RCS loading, and/or SCC Chemistry Section XI, recommends no

components and PWSCC Subsection IWB, further evaluation

(except CASS IWC, and IWD (See Section

and bolting) (Item Program (8.1.14); 3.1.2.1)

Number 3.1.1-36) Water Chemistry

Control Program

(B.1.40); Alloy 600

Aging Management

Program (B.1.1);

Pressurizer

Examinations

Program (B.1.24) - .

Reactor vessel Loss of fracture Thermal Aging and Cast Austenitic Consistent with

internals CASS toughness due Neutron Irradiation Stainless Steel GALL, which

components (Item thermal aging, neutron Embrittlement Evaluation Program recommends no

Number 3.1.1-37) irradiation (B.1.7) further evaluation

embrittlement, and (See Section

void swelling 3.1.2.1)

External surfaces Loss of material due Boric Acid Boric Acid Consistent with

of carbon steel to boric acid corrosion Corrosion Corrosion Program GALL, which

components in -- (B.1.4) - recommends no

RCS pressure further evaluation

boundary (Item - (See Section -

Number 3.1.1-38) - - 3.1.2.1)

Steam generator Loss of material due Inservice Not applicable Consistent with

secondary to erosion Inspection GALL, which

manways and recommends no.

handholds further evaluation

(carbon steel) (See Section

(Item Number i 3.1.2.1)

3.1.1-39)

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- Components Aging Effecm AMPP in LRA -Staff -

-Group : Mechanism: Repot - - - Evaluatio n:

Reactor internals, Loss of material due Inservice Inservice Consistent with

reactor vessel to wear Inspection Inspection-ASME GALL, which

closure studs, Section Xl, recommends no

and core support Subsection IWB, further evaluation

pads (Item IWC, and IWD (See Section

Number 3.1.1-40) Program (B.1.14); 3.1.2.1)

Reactor Vessel

Internals Plates,

Forgings, Welds,

and Bolting

Program (B.1.27);

Bottom-Mounted

Instrumentation

Thimble Tube

Inspection Program

(B..1.5)

Pressurizer Crack initiation and Inservice Inservice Consistent with

integral support growth due to cyclic Inspection Inspection-ASME GALL, which

-(Item Number loading Section Xl, recommends no

3.1.1-41) Subsection IWB, further evaluation

IWC, and IWD (See Section

Program (B.1.14) 3.1.2.1)

Upper and lower Loss of preload due to Inservice Inservice Consistent with

internals stress relaxation Inspection; Loose Inspection-ASME GALL, which

assembly Part and/or Neutron Section Xl, recommends no

(Westinghouse) Noise Monitoring Subsection IWB, further evaluation

(Item Number IWC, and IWD (See Section

3.1.1-42) Program (B.1.14) 3.1.2.1)

Reactor vessel Loss of fracture PWR Vessel Reactor Vessel Consistent with

internals in fuel toughness due to Internals; Water Internals Plates, GALL, which

zone region neutron irradiation Chemistry Forgings, Welds, recommends no

(except embrittlement and and Bolting further evaluation

Westinghouse void swelling Program (B.1.27) (See Section

and B&W baffle 3.1.2.1)

former bolts)

(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 Program GALL, which

heads, PWSCC, and/or Chemistry (B.1.40); Alloy 600 recommends no

tubesheets, and IASCC Aging Management further evaluation

primary nozzles Program (B.1.1); (See Section

and safe ends Inservice 3.1.2.1)

(Item Number Inspection-ASME

3.1.1-44) Section Xi,

Subsection IWB,

IWC, and IWD

Program (B.1.14)

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Component Aging EffectM AMP in GALL FaStaff AMP inLRA 

Group : Mechanism- - Report -- * Eva uation--

Vessel internals Crack initiation and - PWR Vessel Reactor Vessel Consistent with

(except growth due to SCC Intemals; Water Intemals Plates, GALL, which

Westinghouse and IASCC Chemistry Forgings, Welds, recommends no

and B&W baffle and Bolting further evaluation

former bolts) Program (B.1.27); (See Section

(Item Number Water Chemistry 3.1.2.1)

3.1.1-45) Control Program

(B.1.40); Inservice

Inspection-ASME

Section Xl,

Subsection IWB,

IWC, and IWD

.. _ Program (B.1.14)

Reactor internals Loss of preload due to Inservice Not applicable Consistent with

(B&W screws and stress relaxation Inspection; Loose GALL, which

bolts) (Item Part Monitoring recommends no

Number 3.1.1-46) further evaluation

_(See Section

- 3.1.2.1)

Reactor vessel Loss of material due Reactor Head Inservice Consistent with

closure studs and to wear Closure Studs Inspection-ASME GALL, which

stud assembly Section Xl, recommends no

(Item Number Subsection IWB, further evaluation

3.1.1-47) IWC, and IWD (See Section

Program (B.1.14) 3.1.2.1)

Reactor internals Loss of preload due to Inservice Reactor Vessel Consistent with

(Westinghouse stress relaxation Inspection; Loose Internals Plates, GALL, which

upper and lower Part Monitoring Forgings, Welds, recommends no

internal and Bolting further evaluation

assemblies, CE Program (B.1.27); (See Section

bolts and tie rods) Inservice 3.1.2.1) -

(Item Number Inspection-ASME

3.1.1-48) Section XI,

Subsection IWB,.

IWC, and IWD - Program (B.1.14)

The staff's review of the reactor vessel, internals, RCS, pressurizer, and steam generator

components and component types followed one of several approaches. One approach,

documented in Section 3.1.2.1 of this SER, involves the staff's review of the AMR results for the

reactor vessel, internals, RCS, pressurizer, and steam generator components and component

types 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 review of the AMR results for the reactor vessel, internals, RCS, pressurizer, and steam

generator components and component types that the applicant indicated are consistent with the

GALL Report and for which further-evaluation is recommended. A third approach, documentedin Section 3.1.2.3 of this SER, involves the staff's review of the AMR results for the reactor . .

vessel, internals, RCS, pressurizer, and steam generator components and component types

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

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to manage or monitor the aging effects of the reactor vessel, internals, and RCS components and component groups.

3.1.2.1 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Not Recommended

Summary of Technical Information in the Application

In Section 3.1.2.1 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

reactor vessel, internals, RCS, pressurizer, and steam generator components:

* Reactor Vessel Integrity Program

* Inservice Inspection-ASME Section XI, Subsection IWB, IWC, and IWD Program * Water Chemistry Control Program

* Boric Acid Corrosion Prevention Program

* Alloy 600 Aging Management Program

* Control Rod Drive Mechanism and Other Vessel Head Penetration Inspection Program * Bottom-Mounted Instrumentation Thimble Tube Inspection Program * Reactor Vessel Internals Plates, Forgings, Welds, and Bolting Program * Reactor Vessel Internals Cast Austenitic Stainless Steel Program * Cast Austenitic Stainless Steel Evaluation Program * Small Bore Piping Program

* Boric Acid Corrosion Prevention Program

* Bolting and Torquing Activities 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 steam generators, 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 for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether The GALL Report evaluation bounds the plant-specific components contained in these GALL Report component

groups.

The applicant provided a note for each AMR line item. The notes describe the alignemnt of the

information in the tables with the information in the GALL Report. The staff audited those

AMRs with notes A through E, where applicable, 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

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identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions. -

Note B indicates that the AMR line item is- consistent with the GALL Report for component,

material, environment, and aging effect. However, 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. In addition, the staff reviewed and confirmed that the identified exceptions to the

GALL AMPs are acceptable. 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 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

verify consistency with the GALL Report. The staff also determined whether the AMR line item

of the different component is applicable 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 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 also verified whether the AMR line item of

the different component is applicable to the component under review. In addition, the staff-:-

reviewed and confirmed whether the identified exceptions to the GALL-AMPs are acceptable.

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 the applicant credited a different AMP. 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 in a manner 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 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 verify that the material presented in the LRA is applicable

and that the applicant identified the appropriate GALL Report AMRs. The following sections

discuss the staff's evaluation.

3.1.2.1.1 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel

To manage loss of fracture toughness resulting from thermal aging embrittlement of the cast

austenitic stainless steel (CASS) pressurizer spray head, the GALL Report recommends no

*further evaluation if this aging effect is managed using a program consistent with GALL AMP

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XL.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)." In the LRA,

the applicant described CNP AMP B.1.7, "Cast Austenitic Stainless Steel Evaluation" as

consistent with GALL AMP XL.M12. However, the pressurizer spray head is not within its

scope. In the LRA, the applicant proposed to use CNP AMP B.1.24, "Pressurizer

Examinations," instead to manage this aging effect. Section 3.0.3.3.9 of this SER documents

the staff's evaluation of this plant-specific program.

The CNP Pressurizer Examinations Program specifies one-time inspection using visual

examination VT-3 to manage reduction of fracture toughness. This approach is not consistent

with GALL AMP XI.M1 2, which provides for volumetric examination or, alternatively, a plant- or

component-specific flaw tolerance evaluation to demonstrate that the thermally embrittled

material has adequate toughness.

By letter dated June 30, 2004, in RAI B.1.24-2, the staff asked the applicant to justify its use of

the visual examination VT-3 instead of a visual examination VT-1 for the one-time inspection of

the spray head and its associated components in either Unit 1 or Unit 2. Additionally, the staff

asked the applicant to provide information regarding acceptance criteria, the evaluation

methodology for the disposition of indications, and the need for successive examinations for the

one-time inspection of the spray head, spray head locking bar, and coupling. The staff

considers that it is adequate to perform a one-time VT-3 visual examination of spray head

components in one unit. Section 3.0.3.3.9 of this SER provides the complete staff evaluation of

the response to RAI B.1.24-2.

The staff finds that based on the Pressurizer Examinations Program, the applicant has

demonstrated that it will adequately manage the effects of aging so that the component

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.1.2 Core Exit Thermocouple Nozzle Assembly

During the audit and review; the staff noted that the GALL Report does not list the core exit

thermocouple nozzle assembly, including holddown nut, compression collar, and lockwasher.

By letter dated April 23, 2004, the applicant provided the following explanation for their

inclusion:

The thermocouple nozzle assembly pressure-retaining items include the head

- port adapter (pressure housing), holddown nut, compression collar, Grafoile

- seals, seal carrier assembly, and lockwasher. The head port adapter, holddown

nut, and compression collar are fabricated from stainless steel and are subject to

aging management review. The short-lived Grafoil seals, seal carrier assembly,

and lockwasher are replaced each refueling outage and are not subject to an

AMR.

The AMR determined that the compression collar and holddown nut are part of

the bolted connection used to connect the head port adapter to the core exit

thermocouple column, which is part of the reactor vessel internals. The stainless

steel holddown nut and compression collar are exposed to an external-ambient

environment in which there are no aging effects that require management.

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The stainless steel thermocouple nozzle assembly head port adapter is exposed

to an internal environment of borated water and an external-ambient

environment. The applicable aging effects include cracking and loss of material,

which will be managed by the inservice inspection program and water chemistry

control program throughout the period of extended operation. The thermocouple

nozzle assembly head port adapter is attached to a CRDM head nozzle adapter

by means of a threaded connection and a canopy seal weld. The canopy seal

weld is exposed to an external-ambient environment. The applicable aging

effect of the canopy seal weld is cracking, which is managed by the boric acid

corrosion prevention program.

Section 3.0.3.2.1 of this SER documents the staff's evaluation of CNP AMP B.1.4, 'Boric Acid

Corrosion Prevention." The staff evaluated CNP AMP B.1.40.1, "Water Chemistry

Control--Primary and Secondary Water Chemistry Control Program," and CNP AMP B.1.14,

"Inservice Inspection-ASME Section Xi, Subsection IWB, IWC, and IWD," as documented in

Sections 3.0.3.2.15 and 3.0.3.1 of this SER, respectively.

With respect to the Water Chemistry Control and Inservice Inspection Programs, the applicant

manages aging of this component type in a manner consistent with the recommendations of the

GALL Report. The staff reviewed the Boric Acid Corrosion Prevention Program; Section

3.0.3.2.1 of this SER discusses the results of that review.

The staff finds that for the Water Chemistry Control and Inservice Inspection Programs, the

applicant has demonstrated that, given an acceptable Boric Acid Corrosion Prevention

Program, it will adequately manage he effects of aging so that the component intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.1.3 Loss of Mechanical Closure Integrity

The GALL Report recommends the management of the loss of mechanical closure integrity of

stainless steel and nickel-based alloy bolted fasteners by stress relaxation in borated water

using GALL AMP XI.M14, "Loose Part Monitoring," or GALL AMP XI.M15, "Neutron Noise

Monitoring," in addition to ISI.

In the LRA, the applicant proposed to manage this aging effect using the Reactor Vessel

Internals Plates, Forgings, Welds, and Bolting Program (CNP AMP B.1.27) and the Inservice

Inspection-ASME Section XI, Subsection IWB, IWC, and IWD Program (CNP AMP B.1.14).

Section 3.0.3.1 of this SER documents the staff's evaluation of these programs.

In the LRA, the applicant stated that the proposed new Reactor Vessel Internals Program is

intended as an alternative to the Loose Part Monitoring Program. The applicant's program

includes managing the aging effects of loss of preload and loss of mechanical closure integrity

and will be implemented before the period of extended operation. The staff finds that this would

provide adequate management of the aging mechanism. However, the AMR for the core

support holddown spring does not identify the Inservice Inspection Program as applicable to

this aging effect. During the audit, the staff requested that the applicant address this issue. By

letter dated April 23, 2004, in response to this request, the applicant provided additional

clarification. In its response, the applicant stated that the Inservice Inspection Program

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includes the holddown spring (already documented in the LRA for the aging effect of cracking), and that the Reactor Vessel Internals Program will augment the ISI to include acceptable inspection methods for bolted joints, including those necessary to demonstrate that loss of closure integrity from stress relaxation (i.e., loss of preload) will be managed.

The staff finds that based on the Reactor Vessel Internals Program, the applicant has

demonstrated that it will adequately manage the effects of aging so that the component intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.1.4 Flow-Accelerated Corrosion

In the LRA, this component grouping includes the main steam nozzles and the Unit 2 feedwater elbow thermal liners. The GALL Report recommends management of loss of material from the feedwater nozzles as a result of FAC, but the applicant does not manage FAC for these

components, which are protected from FAC by nickel-based alloy thermal sleeves (Unit 1) and carbon steel thermal liners (Unit 2). The sleeves are not subject to FAC; therefore, no program is required for management of this aging effect. The applicant uses CNP AMP B.1.12, "Flow-Accelerated Corrosion," supplemented by the Water Chemistry Control-Primary and Secondary Water Chemistry Control Program (CNP AMP B.1.40.1) to manage this effect. This is consistent with the GALL Report and therefore acceptable to the staff. Sections 3.0.3.1 and 3.0.3.2.15 of this SER, respectively, document the staff's evaluation of these programs.

The staff finds that based on the programs identified above, the applicant has demonstrated

that it will adequately manage the effects of aging so that the component intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

On the basis of its audit and review, the staff determined that for all other AMRs not requiring further evaluation, as identified in LRA Table 3.1.1 (Table 1), the applicant's references to the GALL Report are acceptable and no further staff review is required.

Conclusion

The staff has verified the applicant's claim of consistency with the GALL Report. The staff has 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 AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with the AMRs in the GALL Report. Therefore, the staff finds that the applicant has demonstrated that it will adequately manage the effects of aging for these

components so that their intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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

Is Recommended

Summary of Technical Information in the Application

In Section 3.1;2.2 of the LRA, the applicant provided further evaluation of aging management,

as recommended by the GALL Report for the reactor vessel, internals, and RCS. The applicant

provided information concerning its management of the following aging effects:

* cumulative fatigue damage (PWR/BWR)

* loss of material due to pitting and crevice corrosion (PWR/BWR)

* loss of fracture toughness due to neutron irradiation embrittlement (PWR/BWR)

* crack initiation and growth due to thermal and mechanical loading or stress cracking

(PWR/BWR)

* crack growth due to cyclic loading (PWR)

* changes in dimension due to void swelling (PWR)

* crack initiation and growth due to SCC or PWSCC (PWR)

* crack initiation and growth due to SCC or IASCC (PWR)

* loss of preload due to stress relaxation (PWR)

* loss of section thickness due to erosion (PWR)

* crack initiation and growth due to PWSCC, outer diameter stress corrosion cracking

(ODSCC), or IGA; or loss of material due to wastage and pitting corrosion; or loss of

section thickness due to fretting and wear; or denting due to corrosion of carbon steel

tube support plate (PWR)

* loss of section thickness due to FAC

* ligament cracking due to corrosion (PWR)

* -loss of material due to FAC (PWR)

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

addresses the issues that require further evaluation. 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 staff's audit and review report provides details of this effort.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections.

3.1.2.2.1 Cumulative Fatigue Damage

Fatigue is a time-limited aging analysis (TLAA), as defined in 10 CFR 54.3. Section 4.3 of this

SER provides the staff's evaluation of this TLAA.

3.1.2.2.2 Loss of Material due to Pitting and Crevice Corrosion

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In LRA Section 3.1.2.2.2, the applicant addressed the loss of material of steam generator

assemblies due to pitting and crevice corrosion.

Section 3.1.2.2.2 of the SRP-LR states that the loss of material due to pitting and crevice

corrosion could occur in the steam generator 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 current program may not be

sufficient. In that case, the GALL Report recommends augmented inspections to manage the

aging effect.

The GALL Report recommends the following two programs to manage the aging of steam

generator assemblies due to pitting and crevice corrosion:

(1) GALL AMP Xl.M1 to detect loss of material

(2) GALL AMP XL.M2 to mitigate corrosion

The GALL Report recommends a plant-specific program to conduct augmented inspections.

In the LRA, the applicant credited the Water Chemistry Control-Primary and Secondary Water

Chemistry Control Program (CNP AMP B.1.40.1) to manage the loss of material due to pitting

and crevice corrosion. Section 3.0.3.2.15 of this SER documents the staff's evaluation of CNP

AMP B.1.40.1. The Inservice Inspection-ASME Section Xl, Subsection IWB, IWC, and IWD

Program (CNP AMP B.1.14) supplements this program for secondary-side external components

of the steam generator within the scope of that program. Section 3.0.3.1 of this SER

documents the staff's evaluation of the Inservice Inspection-ASME Section Xl, Subsection

IWB, IWC, and IWD Program.

In LRA Section 3.1.2.2.2, the applicant did not discuss secondary-side internal components of

the steam generator that are outside the scope of the Inservice Inspection Program. In Table

3.1.2-1, the applicant stated that it supplements management of general, pitting, and crevice

corrosion for the steam generator shell assembly and attached components, as well as

components of the secondary-side internals, using CNP AMP B.1.31, "Steam Generator

Integrity Program." Section 3.0.3.1 of this SER documents the staff's evaluation of the Steam

Generator Integrity Program.

The applicant credited the Inservice Inspection Program, which is evaluated in Section 3.0.3.1

of this SER, and the Water Chemistry Control-Primary and Secondary Water Chemistry

Control Program," which is evaluated in Section 3.0.3.2.15 of this SER, for managing the loss of

material due to pitting and crevice corrosion on the internal surfaces of the steam generator

shell.

The staff reviewed NRC IN 90-04, which identifies the need to augment inspections beyond the

requirements of ASME Code Section Xl if general corrosion pitting of the steam generator shell

is known to exist, to differentiate isolated cracks from inherent geometric conditions. The

applicant maintained that these concerns are not applicable to CNP because it has not

experienced significant pitting corrosion of the steam generator shell. The applicant replaced

the Unit 1 steam generators in 2000 and the Unit 2 steam generators in 1988.

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The staff reviewed operating experience, which indicates that no pitting corrosion of the steam

generator shell has been detected to date, and that water chemistry have been maintained for

these new steam generators in accordance with EPRI guidelines. The staff finds that the

augmented inspections recommended by NRC IN 90-04, as referenced in the SRP-LR, do' ot

currently apply to the CNP steam generators.

In the LRA, the applicant stated that the steam generator tubesheet is made of LAS, clad on the

primary side with ni6kel-based alloy. Using only the Water Chemistry Control-Primary and '

Secondary Water Chemistry Control Program to manage the loss of material from the primary

side (in treated, b6rated water) is consistent with the GALL Report and acceptable to the staff.

However,'the staff does not consider this program to be sufficient for managing this loss of

material from the secondary side of the tubesheet. During the'audit, the applicant was asked to'

justify this' position.' By'letter dated April 23, 2004, the applicant responded by stating that the ' -

Steam Generator Integrity Program and Water Chemistry'Control Program will manage loss of

material from thfesecondary side of the tubesheet. This is consistent with the GALL Report and

therefore acceptable to the staff.

In addition, because the' applicant had not detected pitting corrosion on the steam generator

shell since installation, the staff finds that augmented inspections are not required and that the

current Water Chemistry Control and Inservice Inspection Programs, supplemented by the

Steam Generator Integrity Program, are consistent with the recommendations of the GALL

Report and therefore adequate for managing this aging effect.

The staff finds that, based on the programs identified above, the applicant has demonstrated

that it will adequately manage the effects of aging so that the component intended functions will

be maintained consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).-

3.1.2.2.3 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement

Neutron irradiation embrittlement is a TLAA, as defined in 10 CFR 54.3. Section 4.2 of this

SER provides the staff's evaluation of the TLAA on neutron irradiation embrittlement.

3.1.2.2.4 Crack Initiation and Growth due to Thermal and Mechanical Loading or StressCorrosion Cracking

In LRA'Section 3.1.2.2.4, the applicant addressed the potential crack initiation and growth that

could be caused by thermal and mechanical loading or SCC (including IGSCC), and that could

occur in small-bore RCS and connected system piping less than 4 inches nominal pipe size

(NPS 4f).

Section 3.1.2.2.4 of the SRP-LR states that the GALL Report recommends that a plant-specific

destructive examination or a NDE that permits inspection of the inside surfaces of the piping be

conducted to ensure that cracking has not occurred and that the component intended function

will be maintained during the period of extended operation.- The applicant should verify that

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 that the conmponent's inttended function will be maintained during the

*period of extended operation. As indicated in ASME Code Section Xl, 1995 Edition,

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Examination Category B-J or B-F, small-bore piping, defined as piping less than NPS 4", does

not receive volumetric inspection.

The GALL Report recommends GALL AMP XI.M1 to detect loss of material and GALL AMP

XL.M2 to mitigate SCC.

The staff reviewed LRA Section 3.1.2.2.4. The applicant uses the Inservice Inspection-ASME

Section Xl, Subsection IWB, IWC, and IWD Program (CNP AMP B.1.14) the Water Chemistry Control-Primary and Secondary Water Chemistry Control Program (CNP AMP B.1.40.1) to

manage cracking from SCC. Sections 3.0.3.1 and 3.0.3.2.15 of this SER, respectively,

document the staff's evaluation of these programs. In addition, the applicant uses CNP AMP

B.1.30, "Small Bore Piping," which includes a one-time inspection to confirm that significant cracking is not occurring. Section 3.0.3.1 of this SER documents the staff's evaluation of this

program. The staff finds this approach to be consistent with the recommendations of the GALL

Report and therefore acceptable. The implementation of the Small Bore Piping Program is

Commitment #22 of Appendix A in this SER.

The staff finds that the applicant's AMR results are consistent with the GALL Report, and that

the applicant has demonstrated that it will adequately manage the effects of aging so that the

component intended functions will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.2.5 Crack Growth due to Cyclic Loading

As stated in the SRP-LR, fatigue is a TLAA as defined in 10 CFR 54.3. Evaluation of TLAAs is

required in accordance with 10 CFR 54.21 (c)(1). Section 4.3 of this SER provides the staff's

evaluation of the crack growth due to cyclic loading at CNP. 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 due to Void Swelling

In LRA Section 3.1.2.2.6, the applicant addressed changes in dimension resulting from void

swelling that could occur in reactor internals 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 internals components be evaluated to ensure the

adequate management of this aging effect. The GALL Report recommends the evaluation of a

plant-specific AMP to manage the effects of changes in dimension due to void swelling and the

loss of fracture toughness associated with such swelling.

In LRA Section 3.1.2.2.6 and Table 3.1.1, the applicant credited the Reactor Vessel Internals

Plates, Forgings, Welds, and Bolting Program (CNP AMP B.1.27) to manage changes in

dimension caused by void swelling of RVI.

In LRA Table 3.1.2-2, page 3.1-51, the applicant credited the Reactor Vessel Internals Cast

Austenitic Stainless Steel Program to manage distortion of the lower support plate and lower

core plate support column cap in a treated water environment. Additionally, in Sections B.1.27

and B.1.28, "Reactor Vessel Internals Cast Austenitic Stainless Steel," of Appendix B to the

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LRA, the applicant described each program as managing the aging effect of distortion due to

void swelling. The implementation of the Reactor Vessel Internals Cast Austenitic Stainless

Steel Program is Commitment #20 in Appendix A of this SER.

RAI 3.1.2-4

In RAI 3.1.2-4, the staff requested that the applicant update LRA Section 3.1.2.2.6 arid Table

3.1.1, Item 3.1.1-11 , to credit the Reactor Vessel Internals Cast Austenitic Stainless Steel

Program with managing this aging effect or to justify why it should not be credited with

managing this aging effect.

In its response dated September 21, 2004, the applicant agreed with the staff that, as described

in LRA Section B.1.28, the Reactor Vessel Internals Cast Austenitic Stainless Steel Program

will manage change in dimension by void swelling of RVI CASS components. The applicant

stated that LRA Section 3.1.2.2.6 and LRA Table 3.1.1, Item 3.1.1-11, should have included this

program. Table 3.1.2-2 of the LRA correctly identifies the CASS components that are

susceptible to change in dimension by void swelling (distortion) and credits the Reactor Vessel

Internals Cast Austenitic Stainless Steel Program with managing this aging effect. Table 3.1.1,

Item 3.1.1-37, of the LRA also credits this program for the management of void swelling.

On the basis of its review of the applicant's response to RAI 3.1.2-4 and the programs it

credited to manage changes in dimension due to void swelling, the staff finds that the

applicant's AMR results are consistent with the GALL Report, and that the applicant has'

demonstrated that it will adequately manage the effects of aging so that the component

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3). Therefore, the concern described in RAI 3.1.2-4

is resolved.

3.1.2.2.7 Crack Initiation and Growth due to Stress-Corrosion Cracking or Primary Water

Stress-Corrosion Cracking

In LRA Section 3.1.2.2.7, the applicant proposed to manage cracking of nickel-based alloy

components due to PWSCC using the plant-specific CNP AMP B.1.1,-"Alloy 600 Aging

Management." Section 3.0.3.3.1 -of this SER documents the staff's evaluation of this program.

The applicant also stated, in the LRA, that the Alloy 600 Aging Management Program is

supplemented by the Water Chemistry Control-Primary and Secondary Water Chemistry

Control Program (CNP AMP B.1.40.1) and the Inservice Inspection-ASME Section XI,

Subsection IWB, IWC, and IWD Program (CNP AMP B.1.14). Sections 3.0.3.2.15 and 3.0.3.1

of this SER, respectively, document the staff's evaluations of these AMPs.

In the LRA, the applicant further stated that it will manage cracking of the pressurizer spray

head assembly using CNP AMP B.1.24, "Pressurizer Examinations." Section 3.0.3.3.9 of this

SER documents the staff's evaluation of this program. The applicant will manage crack

initiation and growth resulting from SCC in reactor coolant piping and fittings using the Water

Chemistry Control and the Inservice Inspection Programs.

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In addition to the plant-specific AMP recommended by the GALL Report, the applicant agreed

to augment [SI when industry programs identify specific locations or appropriate inspections for

the management of this aging effect.

The staff finds the applicant's approach for managing crack initiation and growth due to SCC

and PWSCC to be consistent with the GALL Report and therefore acceptable. The applicant

agreed to submit the program for review by the staff prior to the period of extended operation.

The staff finds that the applicant appropriately evaluated AMR results that address these aging

mechanisms, as recommended in the GALL Report.

3.1.2.2.8 Crack Initiation and Growth due to Stress-Corrosion Cracking or Irradiation-Assisted

Stress-Corrosion Cracking

In LRA Section 3.1.2.2.8, the applicant addressed crack initiation and growth resulting from

SCC or IASCC that could occur in baffle/former bolts in the reactor.

Section 3.1.2.2.8 of the SRP-LR states that crack initiation and growth due to SCC or IASCC

could occur in baffle/former bolts in the reactors. The GALL Report recommends further

evaluation to ensure the adequate management of these aging effects.

The applicant proposed to use the Reactor Vessel Internals Plates, Forgings, Welds, and

Bolting Program (CNP AMP B.1.27), in conjunction with the Inservice Inspection-ASME

Section Xi, Subsection IWB, IWC, and IWD Program (CNP AMP B.1.14). Section 3.0.3.1 of

this SER documents the staff's evaluation of these two programs. The applicant also credited

the Water Chemistry Control-Primary and Secondary Water Chemistry Control Program (CNP

AMP B.1.40.1) for mitigating damage caused by SCC. Section 3.0.3.2.15 of this SER

documents the staff's evaluation of CNP AMP B.1.40.1.

In the LRA, the applicant stated that it will use volumetric inspections of baffle/former bolt

critical locations to assess cracking. No detectable crack will be considered acceptable for a

baffle bolt, and the critical number (and location) of baffle bolts that must remain intact will be

determined by analysis as part of this program. The industry is addressing the issue of baffle

bolt cracking through the activities of the PWR MRP ITG. Those activities will determine,

develop, and implement the necessary steps and plans to manage the applicable aging effects

on a plant-specific basis. In the LRA, the applicant stated it will follow these efforts and will

apply further understanding of these aging effects as an additional bases for the inspections

under this program. The staff finds this action to be acceptable.

3.1.2.2.9 Loss of Preload due to Stress Relaxation

In LRA Section 3.1.2.2.9, the applicant addressed the loss of preload due to stress relaxation

that could occur in baffle/former bolts in the reactor.

Section 3.1.2.2.9 of the SRP-LR states that the loss of preload as a result of stress relaxation

could occur in baffle/former bolts in the reactor. The GALL Report recommends further

evaluation to ensure the adequate management of this aging effect.

In the LRA, the applicant proposed to use the Reactor Vessel Internals Plates, Forgings,

Welds, and Bolting Program (CNP AMP B.1.27), in conjunction with the Inservice

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Inspection-ASME Section XI, Subsection IWB, IWC, and IWD.Program (CNP AMP B.1.14).

Section 3.0.3.1 of this SER documents the staff's evaluation of the plant-specific CNP AMP

B.1.27,and CNP AMP B.1.14. As recommended by the GALL Report, the applicant augments

the ISIs by volumetric examination to detect and manage this aging effect.

On the basis that the applicant's Reactor Vessel Internals Plates, Forgings, Welds, and Bolting -

Program will be consistent with GALL AMP. XI.M16, the staff finds the applicant's approach for.

managing the loss of preload due to stress relaxation to be consistent with the GALL Report

and therefore acceptable.

3.1.2.2.10 Loss of Section Thickness due to Erosion

In LRA Section 3.1.2.2.10, the applicant addressed the loss of section thickness due to erosion

that could occur in steam generator feedwater impingement plates and supports.

Section 3.1.2.2.10 of the SRP-LR states that the loss of section thickness from erosion could

occur in steam generator feedwater impingement plates and supports. The GALL Report

recommends further evaluation of a plant-specific AMP to ensure the adequate management of:

this aging effect.

The applicant stated, in the LRA, that its steam generator design does not include impingement

plates. Because impingement plates are not part of the CNP steam generator design, the staff

finds that this aging effect does not require management at CNP.

3.1.2.2.11 Crack Initiation and Growth due to Primary Water Stress-Corrosion Cracking,

Outside Diameter Stress-Corrosion Cracking, or Intergranular Attack; or Loss of

Material due to Wastage and Pitting Corrosion; or Loss of Section Thickness due to

Fretting and Wear; or Denting due to Corrosion of Carbon Steel Tube Support Plate

In CNP LRA Section 3.1.2.2.11, the applicant addresses 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 that could occur in nickel-based alloy components of the steam

generator tubes and plugs.

SPR-LR Section 3.1.2.2.11 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 steam generator tubes, repair sleeves and plugs..

The applicant agreed to conform to the steam generator degradation management programr

described in NEI 97-06. The GALL Report recommends the development of an AMP based on

the recommendations of staff-approved NEI 97-06 guidelines, or another alternate regulatory

basis for steam generator degradation management, to ensure the adequate management of:,

this aging effect.

To manage several of the effects of aging, the applicant credits the Steam Generator Integrity

Program (CNP AMP B.1.31) in the LRA. Aging effects managed by the Steam Generator

Integrity Program include crack initiation and growth resulting from the PWSCC, SCC, or IGA or

loss of material caused by wastage and pitting corrosion or deformation due to corrosion which

could occur in nickel-based alloy components of the steam generator tubes and plugs. Section -

.3.0.3.1 of this SER documents the staff's evaluation of the Steam Generator Integrity Program.

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In addition, the applicant stated that it will supplement this program with the Water Chemistry Control-Primary and Secondary Water Chemistry Control Program (CNP AMP B.1.40.1) and

the Inservice lnspection-ASME Section Xl, Subsection IWB, IWC, and IWD Program (CNP AMP B.1.14). Sections 3.0.3.2.15 and 3.0.3.1 of this SER, respectively, discuss the staff's

evaluations of these programs. For general and pitting corrosion, as well as for the assessment

of tube integrity and plugging or repair criteria of flawed tubes, the Steam Generator Integrity Program acceptance criteria conform to NEI 97-06 guidelines.

On the basis of its review of the Water Chemistry Control and Inservice Inspection Programs, the staff finds that the applicant appropriately evaluated the 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 due to Flow-Accelerated Corrosion

In LRA Section 3.1.2.2.12, the applicant addressed the loss of section thickness due to FAC

that could occur in tube support lattice bars made of carbon steel.

Section 3.1.2.2.12 of the SRP-LR states that the loss of section thickness due to FAC could

occur in tube support lattice bars made of carbon steel. The GALL Report recommends the

evaluation of a plant-specific AMP and, on the basis of the guidelines of NRC GL 97-06, development of an inspection program for steam generator internals to ensure the adequate

management of this aging effect.

In the LRA, the applicant stated that its steam generator design does not include carbon steel

tube support lattice bars.

On the basis that carbon steel tube support lattice bars are not part of the CNP steam

generator design, the staff finds that this aging effect does not require management at CNP.

3.1.2.2.13 Ligament Cracking due to Corrosion

In LRA Section 3.1.2.2.13, the applicant addressed ligament cracking resulting from corrosion

that could occur in carbon steel components in the steam generator tube support plate.

Section 3.1.2.2.13 of the SRP-LR states that ligament cracking due to corrosion could occur in

carbon steel components in the steam generator tube support plate. All PWR licensees have

voluntarily agreed to conform to a steam generator degradation management program described in NEI 97-06. The GALL Report recommends the development of an AMP based on

the recommendations of staff-approved NEI 97-06 guidelines, or another alternate regulatory basis for steam generator degradation management, to ensure the adequate management of

this aging effect.

The applicant stated that the CNP Unit 1 steam generators do not have support plates; the

steam generators in Unit 2 have tube support plates made of stainless steel, not carbon steel.

On the basis that CNP Unit 1 has no tube support plate and that the CNP Unit 2 steam

generator tube support plate design does not include carbon steel components, the staff findds

that this aging effect does not require management at CNP.

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3.1.2.2.14 Loss of Material due to Flow-Accelerated Corrosion

In LRA Section 3.1.2.2.14, the applicant addressed the loss of material due to FAC that could

occur in the feedwater inlet ring and supports.

Section 3.1.2.2.14 of the SRP-LR states that loss of material due to FAC could occur in the

feedwater inlet ring and supports. As noted in NRC IN 90-04, NRC IN 91-19, and LER

50-362/90-05-01, this form of degradation has been detected only in certain Combustion

Engineering (CE) System 80 steam generators.- The GALL Report recommends further

evaluation to ensure the adequate management of this aging effect. The GALL Report also

recommends the evaluation of a plant-specific AMP because existing programs may not be

capable of mitigating or detecting the loss of material caused by FAC.: -

In the LRA, the applicant stated that this subsection of the SRP-LR applies only to CE System

80 steam generators and notes that CNP has B&W Type 51 R and Westinghouse Model 51

steam generators for which this form of degradation has not been detected.

On the basis that B&W Type 51 R and Westinghouse Model 51 steam generators are not

subject to FAC in the feedwater inlet ring supports, the staff finds that this component requires

no AMP at CNP.

3.1.2.2.15 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 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 required further evaluation. In addition, the staff reviewed the

applicant's further evaluations against the criteria contained in 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 it will adequately manage the effects of aging 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).-

3.1.2.3 AMR Results That Are Not Consistent With or Not Addressed in the GALL Report

Summary of Technical Information in the Application

In Tables 3.1.2-1 through 3.1.2-5 of the LRA, the staff reviewed additional details of the results

of the AMRs for material, environment, AERM, and AMP combinations that are not consistent

with the GALL Report.

In Tables 3.1.2-1 through 3.1.2-5, the applicant indicated, using notes F through J, that the

GALL Report evaluates neither the identified component nor the material and environment

combination, and provided information concerning the means for managing the aging effect.

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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 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 the GALL Report does not evaluate either the identified component or the

material and environment combination.

Staff Evaluation

For component type, material, and environment combinations that the GALL Report does not

evaluate, 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 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 Rod 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

AERMs for the reactor vessel and control rod drive mechanism (CRDM) pressure boundary.

The applicant identified the following programs that manage the AERMs for the reactor vessel

and CRDM pressure boundary and associated pressure boundary components:

* Reactor Vessel Integrity Program

* Inservice Inspection - ASME Section Xl, Subsection IWB, IWC, and IWD Program

* Water Chemistry Control Program

* Boric Acid Corrosion Prevention Program

* Alloy 600 Aging Management Program

* Control Rod Drive Mechanism and Other Vessel Head Penetration Inspection Program

* Bottom-Mounted Instrumentation Thimble Tube Inspection Program

The applicant identified the following aging effects associated with the reactor vessel and

CRDM pressure boundary components that require management:

* cracking

* loss of material

* reduction in fracture toughness (reactor vessel beltline materials only)

* loss of mechanical closure integrity

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In Table 3.1.2-1 of the LRA, the applicant provided a summary of AMRs for the Reactor Vessel

and CRDM Pressure Boundary and associated pressure boundary components and identified

which AMRs it considered to be not consistent with or not addressed in the GALL Report.

Staff Evaluation

This section provides the results of the staff's evaluation of the applicant's AMR for the aging

effects and the AMPs credited for managing them for the reactor vessel and CRDM pressure

boundary components of the RCS. The staff also reviewed the applicable UFSAR

Supplements to ensure that they adequately describe the AMPs.

Loss of Material in Carbon Steel, Low Alloy Steel, and Low Alloy Steel Internally Clad with

Stainless Steel or Nickel-Based Alloy Exposed Externally to Potentially Leaking Borated Water

Summary of Technical Information in the Application

The applicant identified in LRA Table 3.1.2-1 that loss of material is an AERM for the following

RPV components which are made of carbon steel, LAS, and LAS internally clad with stainless

steel or nickel-based alloy, which may be potentially exposed externally to leaking borated

water:

* bottom head, shell-nozzle course, upper head, and inlet and outlet nozzles (LAS clad -

with stainless steel)

shell rings (LAS clad with stainless steel and nickel-based alloy)

* weld buildup support pads (LAS) -

* vessel flange and closure head flange (LAS clad with stainless steel)

* closure studs, nuts, and washers (LAS)

* lifting lugs (LAS)

* ventilation shroud support ring (carbon steel)

The applicant credited the Boric Acid Corrosion Prevention Program (SER Section 3.0.3.2.1)

with the management of the loss of material in these components.

Staff Evaluation

The applicant identified that loss of material is an applicable aging effect for carbon steel, LAS,

and LAS internally clad with stainless steel or nickel-based alloy RPV components that may be

potentially exposed to leaking borated water. It characterized the AMR for managing these

components as either consistent with the GALL Report line item or consistent with the the GALL,

Report line item except for the component itself.

The'Boric Acid Corrosion Prevention Program is used to manage the aging of carbon steel

SCs, LAS SCs, and electrical components onto which borated water may leak. The staff

evaluation and acceptance of this program can be found in Section 3.0.3.2.1. Using provisions

in the Boric Acid Corrosion'Prevention Program for inspecting, detecting, or monitoring the

degradation of SCs that may be potentially exposed to borated water to manage the loss of

material in SCs is consistent with the GALL Report line items for these listed components and,

therefore, is acceptable to the staff. Hence, the staff finds that the applicant's AMR evaluation

is consistent with the GALL Report, and the applicant has demonstrated the effects of aging will

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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).

Cracking in Nickel-Based Alloy and Low Alloy Steel Clad with Stainless Steel or Nickel Based

Alloy Under Borated Water Environment

Summary of Technical Information in the Application

The applicant identified that cracking is an AERM for the following groups of nickel-based alloy

and LAS clad with stainless steel or nickel-based alloy RPV components which are exposed to

the borated water environment, as indicated in LRA Table 3.1.2-1:

* bottom head, shell-nozzle course, upper head, and inlet and outlet nozzles (LAS clad

with stainless steel)

* flange and closure head flange (LAS clad with stainless steel)

* shell rings (LAS clad with stainless steel and nickel-based alloy)

* in-core instrumentation nozzles (nickel-based alloy)

* core support lugs (nickel-based alloy)

The applicant credited the Water Chemistry Control Program (SER Section 3.0.3.2.15),

Inservice Inspection Program-ASME Section Xl, Subsections IWB, IWC, and IWD (SER Section 3.0.3.1), and the TLAA regarding underclad cracking (SER Section 4.7.4) with the

management of cracking in the first two groups of RPV components listed above. For easy

referencing, this SER refers the second AMP hereafter as the Inservice Inspection Program.

For the remaining three groups of RPV components, the applicant credited three AMPs with the

management of cracking-the Water Chemistry Control Program, the Alloy 600 Aging

Management Program (SER Section 3.0.3.3.1), and the Inservice-Inspection Program.

Staff Evaluation

The applicant identified cracking as an applicable aging effect for nickel-based alloy and LAS

clad with stainless steel or nickel-based alloy RPV components which are exposed to a borated

water environment. The applicant characterized the AMRs for managing these components as

not consistent with the GALL Report line item or not consistent with the GALL Report line item

except for the component itself.

In addition to the Water Chemistry Control and the Inservice Inspection Programs, the applicant

credited the TLAA regarding RPV underclad cracking, which is discussed in Section 4.7.4 of

this SER, with the management of cracking in inlet and outlet nozzles and vessel flange and

closure head flange. Underclad cracking is caused by reheat cracking, the use of high-heat- input welding processes on SA-508, Class 2 forgings. This TLAA has identified fatigue crack

growth to be the dominant degradation mechanism for cracks in this material and has provided justification, as discussed in Section 4.7.4.2 of this SER, for managing the fatigue crack growth

for 60 years for this special class of cracks in RPV LAS base metal immediately beneath the

clad.

The GALL Report line item IV.A2.4-b for inlet and outlet nozzles does not call for the underclad

cracking TLAA to manage cracking under a borated water environment. The GALL Report line

items IV.A2.5-d, IV.A2.5-e, and IV.A2.5-f for vessel flanges do not even list cracking as an

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aging effect under a borated watei environment. Technically, underclad cracking has less

effect on RPV inlet and outlet nozzles and vessel flange and closure head flange than on RPV

shell rings because the stresses associated with the former are lower. Therefore, the-'

applicant's practice of applying the underclad 'racking'TLAA, which relates to RPV shell rings,'

to CNP RPV inlet and outlet nozzles (part of Group 1 components) and vessel flange and

closure head flange-(Group 2.components) exceeds GALL requirements and is acceptable.

RA13.1-8

As mentioned above, the applicant also credited the Water Chemistry Control and Inservice

Inspection Programs for managing cracking in the first two groups of RPV components.'

Industry has used the Water Chemistry Control and Inservice Inspection Programs for years in

operating plants to detect, size, and evaluate cracking, including underclad cracking and ' . I

general SCC in these RPV components. 'Using the Water Chemistry Control and Inservice ,

Inspection Programs to manage cracking in RPV inlet and outlet nozzles is consistent with the':'

GALL Report line item IV.A2.4-b and is appropriate. 'Using the WaterChemristry Control and

Inservice Inspection Programs to manage cracking in'RPV vessel flange and closure'head

flange is also appropriate because the applicant exceeded the GALL Report requirements by

considering cracking as an aging effect for RPV flanges. However, in RAI 3.1-8, for flaws

which were detected and evaluated to date in accordance with ASME Code requirements, the

staff requested that the applicant propose a plan to monitor and evaluate these flaws'

appropriately during the period of extended operation because disposition of these detected

flaws to date was based on a period of 40 years of operation.

In the letter dated October 18, 2004, the applicant responded by stating that "[a] review of -

inservice inspection records determined that CNP has no rejected flaws that were accepted by

analytical evaluation to the end of the service lifetime of the component." Since the applicant

did not perform any flaw evaluation which would require reexamination at the end of current

license, the'staff considers RAI 3.1-8 closed. Hence, the staff concludes that the proposed

management of cracking under a borated water environment for the Group 1 and 2 RPV

components is acceptable.

RAI3.1-9

For Group 3 components (shell ring), footnotes 1 and 8 to LRA Table 3.1.2-1 indicate that

certain shell ring cladding is fabricated of-nickel-based weld material (Alloy 82/182, 52/152),'

and PWSCC is a concern for these welds.' The GALL Report line items IV.A2.5-a, IV.A2.5-b,

IV.A2.5-c, and IV.A2.5-d do not list PWSCC as an aging effect for shell rings under a borated

water environment. Therefore, to assess the AMR review of shell rings, the staff requested the

applicant to identify all locations under "shell rings" in Table 3.1.2-1 that have'nickel-based weld

material exposed to a borated water environment. The staff issued this request as RAI 3.1-9.:-

The applicant responded in the letter dated August 11, 2004, that the only places where shell

rings have a nickel-based weld material is the nickel-based weld cladding under six core

support lugs around the lower shell ring.- Since the applicant has provided information needed'

for assessing the applicability of the proposed AMPS discussed below to these specific -' '

locations in shell rings, the staff considers RAI 3.1-9 to be answered satisfactorily and the issue

resolved.

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The applicant credited the Water Chemistry Control, Alloy 600 Aging Management, and

Inservice Inspection Programs for the management of cracking in shell rings (Group 3

components). As discussed above, the applicant's response to RAI 3.1-9 indicates that the

weld cladding under six core support lugs around the lower shell ring shell rings contains Alloy

82/182 material. The applicant could not find an appropriate GALL Report line item for RPV

shell rings with Alloy 82/182 material; consequently, the applicant has referenced GALL Report

line item IV.C2.5-c for pressurizer shell with Alloy 82/182 cladding and adopted the Inservice

Inspection and Water Chemistry Control Programs, which are recommended by the GALLReport for pressurizer shells, to manage cracking in RPV shell rings. Further, although GALL

line item IV.C2.5-c does not mention the use of the Alloy 600 Aging Management Program for

managing cracking in RPV shell rings, the applicant proposed, in accordance with the current

industry practice on PWSCC, to include the Alloy 600 Aging Management Program to manage

cracking in these components during the extended period of operation. This SER discusses

PWSCC and the Alloy 600 Aging Management Program below with regard to Group 4 and 5

components for which the GALL Report has identified PWSCC, as an aging mechanism. Using

the Alloy 600 Aging Management, Water Chemistry Control, and Inservice Inspection Programs

for the management of cracking in shell rings under a borated water environment is consistent

with the GALL Report.

For Group 4 and 5 components (in-core instrumentation (ICI) nozzles and core support lugs),

the GALL Report line item IV.A2.7-a for bottom head instrument tubes and line item IV.A2.6-a

for core support pads/core guide lugs confirm that the primary cracking mechanism for these

two groups of components is PWSCC, and the GALL Report recommends that the applicant

provide a plant-specific AMP or participate in industry programs to determine an appropriate

AMP for managing PWSCC. The staff's review of the Alloy 600 Aging Management Program

as evaluated in Section 3.0.3.3.1of this SER concludes that the applicant's Alloy 600 Aging

Management Program, which incorporates the industry effort in managing PWSCC generically,

is the plant-specific AMP recommended by the GALL Report for Group 4 and 5 components. In

addition, although GALL Report line items IV.A2.6-a and IV.A2.7-a does not list the Water

Chemistry Control and Inservice Inspection Programs for the management of cracking in Group

4 and 5 components under a borated water environment, adding them as supplemental AMPs

is prudent because improvements in water chemistry are effective in mitigating general

corrosion and SCC. In addition, the Inservice Inspection Program will supplement the

inspection requirements in the Alloy 600 Aging Management Program specifically designed for

managing PWSCC. The staff concludes that using the Water Chemistry Control, the Alloy 600

Aging Management, and the Inservice Inspection Programs to manage cracking in ICI nozzles

and core support lugs exceeds the GALL Report recommendations for these components and,

therefore, is acceptable.

On the basis of its review, the staff finds that the applicant has adequately evaluated the

management of cracking in RPV nickel-based alloy and LAS clad with stainless steel or nickel

based alloy under borated water environment, as recommended in the GALL Report. Since the

applicant's AMR results are either consistent with or exceed the GALL Report requirements, the

staff finds that the applicant has demonstrated that it will adequately mange the effects of aging

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).

1-

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Cracking in Stainless Steel Bottom-Mounted Instrumentation Thimble Tubes Under Borated

Water Environment

Summary of Technical Information in the Application

The applicant identified in LRA Table 3.1.2-1 that cracking is an AERM for the BMI thimble

tubes and bullet plugs which are made of stainless steel and are exposed to a borated water

environment. The applicant credited the Water Chemistry Control and Inservice Inspection

Programs with the management of cracking in the BMI thimble tubes and bullet plugs.

Staff Evaluation

RAI B. 1.5-1

LRA Table 3.1.2-1 lists cracking as an AERM for bottom-mounted instrumentation (BMI) thimble

tubes and bullet plugs. Because the applicant's Bottom-Mounted Instrumentation Thimble Tube

Inspection Program does not mention cracking, the staff requested that the applicant confirm

that cracking for BMI thimble tubes is a credible degradation mechanism requiring aging

management and revise the program, if necessary, to include inspection for cracking due to

SCC. The staff addressed this issue in RAI B.1.5-1.

The applicant responded in its letter dated August 19, 2004, that the Water Chemistry Control

and Inservice Inspection Programs manage cracking caused by SCC. The applicant did not - -

address whether cracking is a credible degradation mechanism for BMI thimble tubes. GALL

Report line item B2.6-c lists only "lost of material/wear" as the aging effect for thimble tubes.

Therefore, considering cracking for thimble tubes is not consistent with the GALL Report. The

staff finds that, compared to the loss of material in thimble tubes due to wear, SCC is

insignificant. The staff based its determination on the following:

* SCC requires a tensile stress to grow while the thimble tubes under external RCP. give

compressive stresses.

* NRC IN 87-44 and Bulletin 88-09 attribute FIV as the cause for BMI thimble tube

thinning and do not mention any indication of SCC.

Hence, the staff concludes that it is prudent and acceptable for the applicant to use the Water

Chemistry Control and Inservice Inspection Programs to manage cracking in BMI thimble tubes

due to SCC. Therefore, the staff's concern described in RAI B.1.5-1 is resolved.

On the basis of its review, the staff finds that the applicant has adequately evaluated the :

management of cracking in stainless steel BMI thimble tubes under a borated water :

environment, as recommended in the GALL report. Since the applicant's AMR evaluation

exceeds the GALL Report requirements, the staff 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 for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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I

Miscellaneous Items - Reduction in Fracture Toughness of Shell Rings and Loss of Mechanical

Closure Integrity for Closure Studs, Nuts, and Washers Exposed Externally to Potentially

Leaking Borated Water

Summary of Technical Information in the Application

The applicant has identified in LRA Table 3.1.2-1 that reduction in fracture toughness is an

AERM for the beltline region of the shell rings that are made of LAS internally clad with

stainless steel or nickel-based alloy and are exposed to the borated water environment. The

applicant credited the Reactor Vessel Integrity Program and the TLAA regarding RPV neutron

embrittlement with the management of reduction in fracture toughness for RPV shell rings.

Further, the applicant identified in LRA Table 3.1.2-1 that the loss of mechanical closure

integrity is an AERM for closure studs, nuts, and washers which are made of LAS and are

exposed externally to potentially leaking borated water. The applicant credited Inservice

Inspection and the Boric Acid Corrosion Prevention Programs with the management of the loss

of mechanical closure integrity for closure studs, nuts, and washers.

Staff Evaluation

The applicant identified reduction in fracture toughness for the beltline region of the shell rings

to be an AERM, as indicated in LRA Table 3.1.2-1. The applicant credited the TLAA regarding

reactor vessel neutron embrittlement (SER Section 4.2) with the management of reduction of

fracture toughness of reactor vessel beltline materials resulting from neutron embrittlement.

This is acceptable because, as discussed in Section 4.2, the TLAA evaluates and determines

the amount of toughness that is appropriate for the CNP reactor vessel beltline materials to

experience through the end of the period of extended operation in terms of the three

parameters specified in the rules on fracture toughness requirements-pressurized thermal

shock (PTS) reference temperatures, RTpTs (10 CFR 50.61), Charpy upper-shelf energy (USE)

values (Appendix G to 10 CFR Part 50) and similar RTs, and nil ductility transition RT (RTNDT),

used in P-T limit calculations (Appendix B to 10 CFR Part 50). The first parameter applies to

PWRs; the remaining two parameters apply to both BWRs and PWRs. Reactor Vessel Integrity

Program will provide valid RPV embrittlement information based on surveillance capsule data to

supplement the prediction of these three parameters.

RAI 3. 1-10

The applicant identified the loss of mechanical closure integrity to be an AERM for reactor

vessel closure studs, nuts, and washers, as indicated in LRA Table 3.1.2-1, and credited the

Inservice Inspection (SER Section 3.0.3.1) and Boric Acid Corrosion Prevention (SER Section

3.0.3.2.1) Programs with the management of this aging effect. The staff's AMR review of GALL

Report line items IV.A2.1-a, -c, -d, and -e for stud assembly confirms that the loss of

mechanical closure integrity is not listed as an aging mechanism, and GALL AMP XI.M3,

"Reactor Head Closure Studs," is the recommended AMP for managing cracking, loss of

material, and wear for these components. Because cracking, loss of material, and wear will

lead to a loss of mechanical closure integrity of reactor vessel closure studs, nuts, and washers,

the staff still references GALL AMP XL.M3 to conduct the evaluation. The main objective of this

GALL program is to provide timely detection of cracks, loss of material, and leakage associated

with closure studs, nuts, and washers, using ISIs in accordance with ASME Code, Section XI,

Subsection IWB, Table IWB 2500-1. The applicant does not have a specific AMP similar to

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GALL AMP XI.M3. -However, the applicant captured the primary elements of GALL AMP.XI.M3,

through its use of the Inservice Inspection and Boric Acid Corrosion Prevention Programs. To

fully justify not having an AMP similar to GALL AMP XI.M3 for CNP, the staff requested the

applicant to address another element in GALL AMP XL.M3 (i.e., preventive measures to mitigate

cracking for these components). The staff addressed this issue in RAI 3.1-10.

The applicant responded in the letter dated August 11, 2004, that preventive measures have :

been incorporated to manage cracking of the reactor vessel closure bolting. These measures

include an application of a magnesium phosphate coating to the bearing surfaces of the reactor

vessel closure bolting during fabrication and the use of a lubricant (neolube) during tensioning

of the bolting, which are consistent with the preventive measures of RG 1.65, uMaterial and

Inspection for Reactor Vessel Closure Studs," specified in GALL Program XI.M3. With this

additional information, the staff concludes that the essential elements of GALL AMP XL.M3 have

been captured by the applicant through its use of the Inservice Inspection and Boric Acid

Corrosion Prevention Programs. Therefore, having an AMP similar to GALL AMP Xl.M3 is not

necessary, and RAI 3.1-10 is closed.

On the basis of its review, the staff finds that the applicant has adequately evaluated the

management of the reduction in fracture toughness.of shell rings and the loss of mechanical:

closure integrity for closure studs, nuts, and washers exposed externally to potentially leaking

borated water, as recommended in the GALL Report.- Since the applicant's AMR results are

consistent with the GALL Report, the staff 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 for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Reactor Vessel and CRDM Pressure Boundaries Summary of Aging Management -

The staff reviewed Table 3.1.2-1 of the LRA, which summarizes the results of AMR evaluations

in the SRP-LR for the reactor vessel and CRDM pressure boundary component groups..;

In the LRA, the applicant stated that the GALL Report does not address the loss of material - -

from components with stainless steel and nickel-based alloy cladding in borated water for

bottom and upper head, shell rings (including the nozzle course), and vessel and closure head.

flanges, as well as inlet and outlet nozzles. The applicant proposed to control this aging

mechanism using the Water Chemistry Control-Primary and Secondary Water Chemistry

Control Program (CNP AMP B.1.40.10. Section 3.0.3.2.15 of this SER documents the staff's

evaluation of this program. -

In LRA Table 3.1.2-1, for each of these same component and material combinations, the

applicant also manages cracking using the Water Chemistry Control Program, the Inservice

Inspection Program, and a plant-specific program, such as the Alloy 600 Aging Management

Program (CNP AMP B.1.1). The staff accepted the applicant's Inservice Inspection Program -

and documents its evaluation of this AMP in SER Section 3.0.3.1. SER Section 3.0.3.3.1 :

summarizes the staff's evaluation of the Alloy 600 Aging Management Program. The applicant

manages cracking in a manner consistent with the GALL Report.

Because the applicant manages the cracking of stainless steel and nickel-based alloy

components through its Water Chemistry Control and Inservice Inspection Programs, and on

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the basis of industry experience that the effects of general and crevice corrosion, as well as

pitting, on stainless steel components in chemically treated, borated water are not significant,

the staff finds that the management of the loss of material aging effect using water chemistry

control is sufficient for stainless steel cladding. This conclusion also applies to loss of material

from nickel-alloy cladding in chemically treated, borated water.

In the LRA, the applicant stated that the cracking of stainless steel cladding of the weld buildup

support pads caused by external-ambient conditions is an aging effect managed under CNP

AMP B.1.14, "Inservice Inspection-ASME Section Xl, Subsection IWB, IWC, and IWD."

Section 3.0.3.1 of this SER documents the staff's evaluation of this AMP. The GALL Report

does not identify this aging effect for this material, environment, and component combination.

The staff finds the applicant's identification of cracking as an applicable effect for these

components to be acceptable and its Inservice Inspection-ASME Section Xl, Subsection IWB,

IWC, and IWD Program to be appropriate for managing this aging effect.

In the LRA, the applicant stated that the GALL Report does not address the loss of material

from components in treated, borated water as an aging effect for nickel-based alloy and

stainless steel. The applicant proposed to use the Water Cheemistry Control Program to

manage this aging effect for nickel-based alloy CRDM nozzles, in-core instrumentation nozzles,

the vent line nozzle and elbow, and Unit 1 flange leak tubes. The same program will be used

for stainless steel Unit 1 inlet and outlet nozzle safe ends CRDM housing adapters, in-core

instrumentation nozzle safe ends and housing cap, in-core instrumentation nozzle safe ends,

the BMI thimble guide tubes and bullet plugs, the thimble seal table, the vent line safe end,

CRDM housing, core exit thermocouple nozzle assembly, holddown nut, compression collar,

lockwasher, CRDM housing cap, and Unit 2 flange leak tubes.

In LRA Table 3.1.2-1, for each of these same component and material combinations, the

applicant also manages cracking using the Water Chemistry Control Program, the Inservice

Inspection Program, and a plant-specific program, such as the Alloy 600 Aging Management

Program (CNP AMP B.1.1) or the Control Rod Drive Mechanism and Other Vessel Head

Penetration Inspection Program (CNP AMP B.1.9). The staff accepted the applicant's Inservice

Inspection Program and documents its evaluation of this AMP in SER Section 3.0.3.1. The

staff reviewed the Alloy 600 Aging Management and Control Rod Drive Mechanism and Other

Vessel Head Penetration Inspection Programs. SER Sections 3.0.3.3.1 and 3.0.3.2.3,

respectively present the results of this review. The staff finds that the applicant manages

cracking in a manner consistent with the GALL Report.

The staff finds that the management of this aging effect using water chemistry control is

sufficient on the basis (1) that the applicant's management of cracking of nickel-based alloy and

stainless steel components in treated, borated water is consistent with the GALL Report, and

(2) industry experience that the effects of general corrosion, crevice corrosion, and pitting, on

stainless steel components in chemically treated, borated water are not significant. The staff

has reached a similar conclusion for the loss of material from nickel-alloy components in

chemically treated, borated water.

In the LRA, the applicant stated that it manages the loss of material for nickel-based alloy in

borated water for core support lugs using the Water Chemistry Control Program, in addition to

the Inservice Inspection Program as specified in the GALL Report. The staff finds the

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combination of this preventive/mitigative program with an inspection program to bean'

acceptable way to manage this aging effect.

During the audit and review, the 'staff noted that the applicant h~andled cracking of stainless'

steel alloy in treated, borated water in a manner consistent with the GALL Report for the core

exit thermocouple nozzle assembly, but the head port adapter (holddowni nut, compression

collar, and lockwasher) is not exposed to the same environment. By letter dated April 23, 2004,

the applicant provided the following response tothe audit question:

The stainless steel thermocouple nozzle assembly head port adapter is exposed

to an internal environment of borated water and an external-ambient

environment. The applicable aging effects include' cracking and loss of material,

which will be managed by the Inservice Inspection Program and the Water

Chemistry Control Program throughout the period of extended operation.

The thermocouple nozzle assembly head port adapter is attached to a CRDMhead nozzle adapter by means of a threaded connection and a canopy seal '

weld. The canopy seal weld is exposed to an external-ambient environment. '

The applicable aging effect of the canopy seal weld is cracking, which is

managed by the Boric Acid Corrosion Prevention Program.

The staff finds that the applicable aging effects are consistent with the GALL Report.

Therefore, the response is acceptable.

RAI 3.1.2-1

In Table 3.1.2-1, the applicant identified cracking as an AERM for Reactor Vessel and CRDM

Pressure Boundary components manufactured from nickel-based alloys and stainless steel

alloys exposed to treated (borated) water environments. The applicant identified the flange' leak

tubes as the components that are subject to cracking. The applicant stated that the flange leak

tubes in Unit 1 are made from nickel-based alloys and the flange leak tubes from Unit 2 are

made from stainless'steel. The Water Chemistry Control, Inservice Inspection, and Alloy 600

Aging Management (Unit 1 only) Programs manage-the aging effect. The applicant stated that

the component, material, environment, aging effect and aging management program is not

consistent with the GALL Report. '

The GALL Report item A2.1-f states that a plant specific AMP must be evaluated because

existing programs may not be capable of mitigating or'detecting crack initiation and growth due

to SCC in the vessel flange leak detection line. The applicant did not identify how SCC will be

managed in the stainless steel flange-leak tubes.'2 Therefore, in-RAI 3.1.2-1 dated July 28,

2004, the staff requested the following action of the applicant:

The staff requests that the applicant identify the aging management program

that will be used to mitigate or detect crack initiation and growth due to SCC in

the Stainless Steel vessel flange leak tubes. Included should be a discussion

about'corrective actions involving repair/replacement.

In its supplemental letter dated August 11,:2004, the applicant's response to RAI 3.1.2-1, stated

that the Unit 2 stainless steel flange leak tubes listed in LRA Table 3.1.2-1 are contained

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entirely within the reactor vessel flange. Stainless steel piping is attached to these tubes, external to the vessel. The category of RCS stainless steel piping of less than NPS 4", as listed

in LRA Table 3.1.2-3, includes this piping. The applicant will manage SCC aging effects on the

stainless steel reactor vessel flange leak detection tubes and external piping using a

combination of the Primary and Secondary Water Chemistry Control Program; the Inservice

Inspection-ASME Section Xl, Subsection IWB, IWC, and IWD Program; and, for the piping, the

Small Bore Piping Program. The applicant stated that if required, evaluation, repair, and

replacement are performed in accordance with applicable ASME Code, Section Xl

requirements.

Based upon the above information, the staff finds the applicant's management of cracking in

the vessel flange leak tubes to be appropriate. Therefore, the staff's concern described in RAI

3.1.2-1 has been resolved.

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 and CRDM 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 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).

3.1.2.3.2 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 for the RVI. The applicant identified the following programs that manage the AERMs

for the RVI and associated pressure boundary components:

* Reactor Vessel Internals Plates, Forgings, Welds, and Bolting Program * Reactor Vessel Internals Cast Austenitic Stainless Steel Program * Water Control Chemistry Program

* Inservice Inspection-ASME Section Xl, Subsection IWB, IWC, and IWD Program

In Table 3.1.2-2 of the LRA, the applicant provided a summary of AMRs for the reactor vessel

internals and associated pressure boundary components and identified which AMRs it

considered to be not consistent with or not addressed in the GALL Report.

Staff Evaluation

This section provides the results of the staff's evaluation of the applicant's AMR for the aging effects and the AMPs credited for managing them for the RVI components. The staff also

reviewed the applicable UFSAR Supplements to ensure that the AMPs are adequately described.

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Cracking and Loss of Mechanical Closure Integrity in Selected Stainless Steel Reactor Vessel

Internals

Summary of Technical Information in the Application

The applicant identified that cracking is an AERM for the following stainless steel components

that are exposed to the borated water environment, as indicated in LRA Table 3.1.2-2:

* core baffle bolts and core former bolts

* upper support plate (Unit 1 only)

* deep beam sections ' * upper support columns (excluding CASS or CASS components)

* support column bolts

Staff Evaluation

All of the components listed above, except for core baffle and core former (baffle/former) bolts,

are considered to be upper core support structure components. As indicated in the component '

listing above, this AMR does not include the CASS components in upper support columns.' The

applicant credited the Water Chemistry Control (SER Section 3.0.3.2.15), Inservice Inspection

(SER Section 3.0.3.1), and Reactor Vessel Internals (SER Section 3.0.3.1) Programs with the

management of cracking in these components.

The applicant identified that cracking is an applicable aging effect for the above listed stainless

steel RVI that are exposed to the borated water environment and categorized the AMR for

these components as not consistent with the corresponding GALL Report line item. GALL

Report line item IV.B2.4-c for baffle/former bolts recommends a plant-specific program with

appropriate'augmented visual inspections to mlanage cracking in this component; GALL line

items (IV.B2.1-a, IV.B2.1-e, IV.B2.1-i, IV.B2.5-e, and IV.B2.5-k) for the upper core support

structure components listed above recommend the Reactor Vessel Internals and Water

Chemistry Control Programs to manage cracking in them. The applicant provided information

beyond that required by the GALL Report for managing cracking in these components by

crediting the plant-specific AMP recommended by the GALL Report for the baffle/former bolts

and the AMPs recommended by the GALL Report for the upper core support structure

components with the management of cracking in all the components listed above. As

discussed in Section 3.0.3.1 of this document, the applicant's Reactor Vessel Internals Program

contains this plant-specific program for baffle/former bolts. Since the staff has accepted the

Reactor Vessel Internals Program, the AMP for managing cracking for all components listed

above, as indicated in SER Section 3.0.3.1, this specific AMR review is also acceptable. The

Water Chemistry Control Program and Inservice Inspection Program will supplement Reactor

Vessel Internals Program in managing cracking in these components.

The applicant credited the Inservice Inspection and Reactor Vessel Internals Programs with the

management of another aging effect, the loss of mechanical closure integrity. GALL Report

line item IV.B2.4-h recommends the use of the same plant-specific AMP discussed above for

managing cracking to manage the loss of preload/stress'relaxation of baffle/former bolts. 'The

staff considers loss of mechanical closure integrity to be equivalent to the loss of preload/stress

relaxation. Therefore, based on the acceptance of the Reactor Vessel Internals Program, the

staff determines that using this AMP for managing the loss of mechanical closure integrity of

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baffle/former bolts is appropriate. The Inservice Inspection Program will supplement the

Reactor Vessel Internals Program in managing the loss of mechanical closure integrity of

baffle/former bolts.

For the upper core support structure components listed above, GALL Report line items IV.B2.1-

k and IV.B2.5-h recommend the use of the Inservice Inspection Program and a "loose part

monitoring" program to manage the loss of mechanical closure integrity. The staff reviewed

GALL AMP XI.M14, "Loose Part Monitoring," and LRA Table B-1 regarding justification for not

having a CNP AMP similar to GALL AMP XI.M14. Since cracking is an early indication of loose

part generation, the staff concludes that adequate management of cracking in these

components through Reactor Vessel Internals Program could reduce the probability of having

loose parts from these components. Therefore, the staff accepts this CNP AMR for managing

the loss of mechanical closure integrity of these components. The Inservice Inspection

Program will supplement the Reactor Vessel Internals Program in managing the loss of

mechanical closure integrity of the upper core support structure components.

On the basis of its review, the staff finds that the applicant has adequately evaluated the

management of cracking and the loss of mechanical closure integrity in the selected stainless

steel RVI components listed above, as recommended in the GALL Report. Since the

applicant's AMR results are either consistent with or exceed the GALL Report requirements, the

staff 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 for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Reactor Vessel Internals Summary of Aging Management

In the LRA, the applicant stated that the GALL Report does not address the loss of material for

stainless steel (including CASS) in treated, borated water. This aging effect is considered for

the following components:

* core barrel, flange, outlet nozzle, and fasteners

* core former plates, baffle plates, baffle bolts, former bolts, and lower plate

* lower support columns

* diffuser plate

* lower support plate

* lower core plate support column cap

* secondary core support assembly

* thermal shield

* upper support plate (Unit 1)

* deep beam sections

* upper support columns

* support column bolts

* upper core support column mixing device

* upper core support column orifice base

* upper support plate (Unit 2)

* upper core plate and plate alignment pins

* lower support radial keys

* holddown spring

* guide tube assemblies

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* upper system thermocouples

* lower system flux thimbles

The applicant stated that the GALL Report does not address loss of material for nickel-based

alloy in treated, borated water. This aging effect is considered for clevis insert fasteners. The

applicant proposed to manage loss of material for this material-environment combination using

only its Water Chemistry Control-Primary and Secondary Water Chemistry Control Program

(CNP AMP B.1.40.1). Section 3.0.3.2.15 of this SER documents the staff's evaluation of this -

program.

In LRA Table 3.1.2-2, for each of these same component and material combinations, the

applicant also manages cracking using the Water Chemistry Control and Inservice Inspection

Programs and a plant-specific program, such as CNP AMP B.1.28, "Reactor Vessel Internals

Cast Austenitic Stainless Steel," or CNP AMP B.1.27, "Reactor Vessel Internals Plates,

Forgings, Welds, and Bolting." The staff accepted the applicant's Inservice Inspection Program

and documents its evaluation of this AMP in Section 3.0.3.1 of this SER. The staff reviewed

Reactor Vessel Internals Cast Austenitic Stainless Steel Program and documents its evaluation

in Section 3.0.3.1 of this SER. The staff reviewed the Reactor Vessel Internals Plates,

Forgings, Welds, and Bolting Program and summarizes the results of its review in Section -

3.0.3.1 of the SER. The staff finds that the applicant manages cracking in a manner consistent

with the GALL Report.

The staff finds that management of this aging effect using water chemistry control is sufficient

on the basis (1) that cracking of stainless steel (including CASS) and nickel-based alloy

components in treated, borated water is managed consistent with the GALL Report, and (2) of

industry experience that the effects of general corrosion, crevice corrosion, and pitting on

components made of stainless steel (including CASS) in chemically treated, borated water are

not significant. The staff reached the same conclusion for the loss of material from nickel-alloy

components in chemically treated, borated water.

In the LRA, the applicant stated that it manages the aging effects of the nickel-based alloy

clevis insert block, control rod guide tube pin, and fuel assembly guide pin using the Inservice

Inspection and Water Chemistry Control Programs. On the basis that the GALL Report *

suggests managing aging effects for these components using ISI, the staff finds the applicant's

approach to be 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 RVI

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). - - -

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I

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

AERMs for Class 1 piping, valves and RCPs. The applicant identified the following programs

that manage the AERM for the Class 1 piping, valves, and RCPs and associated pressure

boundary components:

* Water Chemistry Control Program

* Inservice Inspection - ASME Section Xl, Subsection IWB, IWC, and IWD Program

* Cast Austenitic Stainless Steel Evaluation Program

* Small Bore Piping Program

* Boric Acid Corrosion Prevention Program

Bolting and Torquing Activities Program

In Table 3.1.2-3 of the LRA, the applicant provided a summary of AMRs for the Class 1 piping,

valves, and RCPs and associated pressure boundary components and identified which AMRs it

considered to be not consistent with or not addressed in the GALL Report.

Staff Evaluation

This section provides the results of the staff's evaluation of the applicant's AMR for the aging

effects, and the AMPs credited for managing them, in Class 1 piping of the RCS. The staff also

reviewed the applicable UFSAR Supplements to ensure that the AMP descriptions are

adequate.

Aging Effects

In Section 3.1 of the LRA, the applicant performed a review of information generated from

industry experience and NRC generic communications relative to the RCS components to

ensure that the AERMs for a specific material-environment combination are the only aging

effects of concern for CNP.

The LRA identified the following applicable aging effects for the Class 1 piping, valves, and

RCPs of the RCS:

* cracking

* reduction in fracture toughness

* loss of material

* loss of mechanical closure integrity

* fouling

Table 3.1.2-3 of the LRA identifies the components in the RCS Class 1 piping that are subject

to an AMR. This table also includes components which the GALL Report evaluates. The

components that the applicant indicated are consistent with the GALL Report need no

additional evaluation because the staff accepts the GALL Report's conclusions with respect to

those components and programs that do not require further evaluation.

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Table 3.1.2-3 also includes components tha the GALL Report does not evaluate. The table

identifies the aging effects, materials, environments, and programs proposed for managing the

aging effects.- The staff has reviewed the information in this table and finds that the applicant

has identified the applicable aging effects.

On the basis of the applicant's review of industry experience and NRC generic communication

relative to the RCS components, the staff finds that the applicant has identified the appropriate

aging effects for the materials and environments associated with the Class 1 piping of the RCS.

Aging Management Programs

The applicant credited the following AMPs to manage the aging effects described above for the

Class 1 piping, valves, and RCPs of the RCS:

* -Water Chemistry Control Program

* Inservice Inspection-ASME Section IX, Subsection IWB, IWC, and IWD Program

* Cast Austenitic Stainless Steel Evaluation Program

* Small Bore Piping Program

* Boric Acid Corrosion Prevention Program

* -Bolting and Torquing Activities Program

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations in the

SRP-LR for the-Class 1 piping, valves, and RCP component groups. The staff finds that the

programs proposed for managing the aging effects for the component types in this system are

consistent with the GALL Report.

In the LRA, the applicant stated that it addresses the loss of material for CASS in treated,

borated water using the Water Chemistry Control-Primary and Secondary Water Chemistry

Control Program (CNP AMP B.1.40.1) and the Inservice Inspection-ASME Section Xl, -

Subsection IWB, IWC, and IWD Program (CNP AMP B.1.14) for the hot- and cold-leg pipe and

fittings, crossover-leg pipe and fittings, Class 1 valve bodies and bonnets (NPS 2.5" and NPS

less than 2"), RCP casing, main closure flange, pressurizer surge line, piping and fitting

(including blind flanges) (NPS 4' and NPS less than 4"), branch nozzles (NPS 4" and NPS less

than 4"), thermal sleeves, orifices, and Class 1 valve bodies and bonnets (NPS 2.5" and NPS-&

less than 2"). Sections 3.0.3.2.15 and 3.0.3.1 of this SER, respectively, document the staff'sevaluation of these two programs. This is consistent with the recommendations in the GALL

Report for managing other components of the same material in a similar environment. On that

basis, the staff finds this approach to be acceptable.

In the LRA, the applicant stated that it will manage the loss of material from the stainless steel

thermal barrier heat exchanger in treated water using the Water Chemistry Control Program.,

On the basis of industry experience that the effects of general and crevice corrosion, as well as

pitting, on components made of stainless steel in chemically treated water and treated, borated

water are not significant, the staff finds that management of this aging effect using water

chemistry control is sufficient.

In the LRA, the applicant stated that it will manage cracking of LAS and stainless steel bolting

material using the Inservice Inspection-ASME Section Xl, Subsection IWB, IWC, and IWD

Program (CNP AMP B.1.14).--Section 3.0.3.1 of this SER documents the staff's evaluation of

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this program. To manage cracking of the bolting material for valves and blind flanges, as well

as main flange bolts, the applicant proposed to use the Inservice Inspection Program. Although

a the applicant cited a precedent, the staff was unable to confirm its applicability. For the

component referenced, the GALL Report recommends a program consistent with GALL AMP

XI.M18, which invokes the guidelines of NUREG-1339 to prevent and mitigate bolting

degradation.

RAI 3.1.3-1

By letter dated August 20, 2004,in RAI 3.1.3-1, the staff requested that the applicant explain its

rationale for excluding bolting material for valves and blind flanges, as well as main flange bolts,

from the scope of its Bolting and Torquing Activities Program (CNP AMP B.1.2) or to confirm

that it is managed using this program. In a letter dated September 2, 2004, in response to RAI

3.1.3-1, the applicant stated that it credited the Bolting and Torquing Activities Program for

managing the loss of mechanical closure integrity for the valve and pump bolting listed in LRA

Table 3.1.2-3. The applicant also stated that the aging effect of cracking is listed separately for

these same components, and is managed by the Inservice Inspection Program, which is more

appropriate for closure bolting in Class I systems.

On the basis of its review of the applicant's response to RAI 3.1.3-1, the staff finds that the

applicant will adequately manage all aging effects of bolting material for valve and blind flanges

and main flange bolts by use of the Inservice Inspection and Bolting and Torquing Activities

Programs. The staff further concludes that the applicant will manage these aging effects

adequately during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Therefore, the staff's concern described in RAI 3.1.3-1 is resolved.

In Table 3.1.2-2, the applicant identified that cracking is an AERM for Class 1 piping

components manufactured from CASS and stainless steel that are exposed to borated water

environments. The applicant identified the hot-leg pipe and fittings, cold-leg pipe and fittings,

crossover-leg pipe and fittings, and pressurizer surge line as subject to cracking, and the AMP

as the leak before break (LBB) TLAA. The applicant stated that it performed an LBB analysis

for the CNP RCS primary loop and the pressurizer surge line. The analyses considered the

thermal aging of CASS piping and the fatigue transients that drive the flaw growth over the

operating life of the plant. The analyses indicated that the properties for the CASS piping

material are acceptable because they will not degrade below the fully aged properties in the

extended period of operation. The applicant also indicated that the results of the RCS transient

cycle definition review determined that the RCS design transients originally defined for 40 years

are acceptable for 60 years of operation. The applicant also stated that, in addition to the LBB

TLAA, it will use the Water Chemistry Control and Inservice Inspection Programs to manage

cracking. The staff concludes that the LBB TLAA, combined with the Water Chemistry Control

and Inservice Inspection Programs, will effectively manage cracking in CASS components.

On the basis of its review, the staff finds the applicant's management of cracking for Class 1

piping components manufactured from CASS and stainless steel exposed to borated water

environments is acceptable.

In Table 3.1.2-2, the applicant identified that the loss of material is an AERM for Class 1 valve

components manufactured from LAS and exposed to an external-ambient environment. The

applicant manages this aging effect using the Boric Acid Corrosion Prevention Program. The

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applicant identified the components as Class 1 valve bodies and bonnets less than 2.5 inches

and bolting material for valves and blind flanges. The aging effect for this component is not

addressed by the GALL Report; however, the AMP is consistent with GALL AMP XI.M10. The

aging effect for the bolting material for valves and blind flanges is consistent with the GALL

Report for this component, environment, and material, and the AMP is consistent with GALL

AMP XI.M10. The applicant stated that the Boric Acid Corrosion Prevention Program relies on

the implementation of recommendations in NRC GL 88-05 to monitor the condition of ferritic

steel components onto which borated reactor water may leak. The applicant stated that

periodic visual inspection of adjacent SCs and supports for evidenceof leakage and corrosion.

is an element of the GL 88-05 monitoring program.

RAI 3.1.2-2

The applicant did not identify which aging mechanisms could lead to loss of material in the

above components that are fabricated from'alloy steel or carbon steel, although the AMP

credited with aging management appears to imply that the applicant'only considered potential

leakage of the borated coolant as a mechanism that could induce loss of material from the

external surfaces of these components. Alloy steel and carbon steel components may also be

susceptible to general corrosion in atmospheric environments, if the atmospheres are damp,

moist, or humid. Therefore, in RAI 3.1.2-2, dated July 28, 2004, the-staff requested the

following action of the applicant:

The staff requests that the applicant identify the aging mechanism that CNP has

determined are capable of inducing loss of material in alloy steel or carbon steel of the

above components that are exposed externally to the inside environments. In addition,

the applicant is requested to describe the inside environment and whether the applicant

is managing the water vapor content in the inside environment to low humidity levels.,

The staff seeks further clarification whether the applicant considers loss of material due

to general corrosion is an applicable aging effect for external surfaces of alloy steel or

carbon steel components that are exposed to the inside environment. If not, the

applicant is requested to provide technical justification why CNP does not consider

general corrosion to be an aging mechanism that needs management in the external

surfaces of alloy steel or carbon steel co'mponrents during the extended periods of

operation.

In its supplemental letter dated August 11, 2004, the applicant provided the following response

to RAI 3.1.2-2:

Containment temperature is maintained below 120 degrees Fahrenheit (

0F) in

the containment lower compartment and below 1 00F in the containment upper.

compartment; humidity is not managed inside containment. No Class 1 valves or

low alloy steel materials are listed in LRA Table 3.1.2-2; they are, however, listed

in LRA Table 3.1.2-3.' The' representative component types listed include

selected low'alloy Class 1'valve bonnets and low alloy steel bolting associated

with' valves blind flanges.' Low alloy steel components such as ferritic valve

bonnets and ferritic bolting are susceptible to loss of material due to boric acid

corrosion that might result from system leakage onto these components.

-Because the valve components are inside containment, no significant general

corrosion is expected. Under the Boric Acid Corrosion Preventive Program

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described in LRA Section B.1.4, evidence of moisture that could cause boric acid

corrosion (or general corrosion) on ferritic surfaces is detected by visual

inspection and evaluated by engineering to determine the leakage source, extent

of degradation, and required corrective actions. Therefore, loss of material of

low alloy steel valve bonnets and low alloy steel closure bolting will be managed

by the Boric Acid Corrosion Preventive Program for the period of extended

operation.

Based upon the above information, the staff finds the applicant has provided an acceptable

AMP for managing the loss of material in alloy steel or carbon steel components that are

exposed externally to the inside environments. Therefore, the staff's concern described in RAI

3.1.2-2 is resolved.

In LRA Table 3.1.2-3, the applicant identified that a loss of mechanical closure integrity is an

AERM for Class 1 valve components manufactured from LAS and stainless steel material and

exposed to an external-ambient environment. The Inservice Inspection, Bolting and Torquing

Activities, and Boric Acid Corrosion Prevention Programs manage this aging effect. The

applicant identified the components as bolting material for valves and blind flanges. The aging

effect, material, and environment combination is consistent with the GALL Report, but the

report credits a different AMP. Item IV.C2.4-g of the GALL Report credits the Boric Acid

Corrosion Prevention Program, and requires no further evaluation. The staff concludes that the

Inservice Inspection, Bolting and Torquing Activities, and Boric Acid Corrosion Prevention

Programs will effectively manage the loss of mechanical closure integrity for Class 1 valve

components manufactured from LAS and stainless steel.

Based upon the above information, the staff finds that the applicant has provided an acceptable

AMP for managing the loss of mechanical closure integrity for Class 1 valve components

manufactured from LAS and stainless steel that are exposed to an external ambient

environment.

The applicant identified in LRA Table 3.1.2-3 that cracking is an AERM for RCPs manufactured

from CASS and exposed to a treated (borated) water environment. The applicant identified the

components as casings and the AMP as the ASME Code Case N-481 Evaluation TLAA. The

applicant stated that the aging effect identified is not in the GALL Report for this component,

material, and environment combination. The applicant stated in the TLAA that it generically

evaluated a demonstration of compliance of the primary loop pump casings with ASME Code

Case N-481 for all Westinghouse plants in WCAP-1 3045, "Compliance to ASME Code Case N481 of the Primary Loop Pump Casings of Westinghouse Type Nuclear Steam Supply

Systems." The applicant conducted a CNP-specific Code Case N-481 evaluation in WCAP13128, "Demonstration of Compliance of the Primary Loop Pump Casings of D.C. Cook Units 1

and 2 to ASME Code Case N-481." The analysis considered thermal aging and fatigue crack

growth to be influenced by time and relied on fully aged stainless steel material properties. The

analyses concluded that the properties for the cast stainless casing material are acceptable

because they will not degrade below the fully aged properties during the extended period of

operation. The applicant stated that the Fatigue Monitoring Program, which is discussed in

Appendix B to the LRA, monitors thermal fatigue design transients for the period of extended

operation. The applicant further stated that, in addition to the ASME Code Case N-481

Evaluation TLAA, the Water Chemistry Control and Inservice Inspection Programs are also

included to monitor and detect/control cracking in the RCP casings. The staff concludes that

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the ASME Code Case N-481 Evaluation TLAA, combined with the Water Chemistry Control and

Inservice Inspection Programs, will effectively manage cracking in RCP components

manufactured from CASS.

On the basis of the above information, the staff finds the applicant has provided an acceptable

AMP for RCPs manufactured from CASS and exposed to a treated (borated) water

environment.

In LRA Table 3.1.2-2, the applicant identified that the loss of material is an AERM for RCP

components manufactured from LAS and exposed to an external-ambient environment. The

applicant manages this aging effect using the Boric Acid Corrosion Prevention Program. The

applicant identified the components requiring management as the main flange bolts. The GALL

Report does not identify the aging effect for this component, however, the applicant's AMP is

consistent with GALL AMP XI.M10. The aging effect for the main flange bolts is consistent

with the GALL Report for this component, environment, and material combination, and the AMP

is consistent with GALL AMP XI.M10. The applicant stated that the Boric Acid Corrosion

Prevention Program relies on the implementation of recommendations in NRC GL 88-05 tomonitor the condition of ferritic steel components onto which borated reactor water may leak.

The applicant stated that periodic visual inspection of adjacent SCs and supports for evidence

of leakage and corrosion is an element of the GL 88-05 monitoring program.

RAI 3.1.2-3

The applicant did not identify which aging mechanisms could lead to loss of material in the

above components that are fabricated from alloy steel or carbon steel, although the AMP.

credited with aging management appears to imply that the applicant only considers potential

leakage of the borated coolant as a mechanism that could induce loss of material from the

external surfaces of these components. Alloy steel and carbon steel components may also be

susceptible to general corrosion in atmospheric environments, if the atmospheres are damp,

moist, or humid. Therefore, in RAI 3.1.2-3, dated July 28, 2004, the staff requested the

following action of the applicant:

The staff requests that the applicant identify the aging mechanism that CNP has

determined are capable of inducing loss of material in alloy steel or carbon steel of the

above components that are exposed externally to the inside environments. In addition,

the applicant is requested to describe the inside environment and whether the applicant

is managing the water vapor content in the inside environment to low humidity levels.

The staff seeks further clarification whether the applicant considers loss of material due

to general corrosion is an applicable aging effect for external surfaces of alloy steel or -

carbon steel components that are exposed to the inside environment.. If not, the

applicant is requested to provide technical justification why CNP does not consider

general corrosion to be an aging mechanism that needs management in the external

surfaces of alloy steel or carbon steel components during the extended periods of

operation.

In its supplemental letter dated August 11, 2004, the applicant's response to RAI 3.1.2-3 stated

that the containment temperature is maintained below 49 OC (120 OF) in the containment lower

compartment and below 38 OC (100 0F) in the containment upper compartment; however,

humidity is not managed inside containment. The applicant stated that no reactor coolant pump

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(RCP) or LAS materials are listed in LRA Table 3.1.2-2, but the LAS RCP main flange bolting is

listed. LAS components, such as bolting, are susceptible to he loss of material due to boric

acid corrosion that might result from system leakage onto these components. Since the

components are inside containment, no significant general corrosion is expected. The applicant

stated that under the Boric Acid Corrosion Prevention Program described in LRA Section B.1.4,

evidence of moisture that could cause boric acid corrosion (or general corrosion) on ferritic

surfaces is detected by visual inspection and evaluated by engineering to determine the

leakage source, extent of degradation, and required corrective actions. The applicant indicated

that the Boric Acid Corrosion Prevention Program will manage the loss of material of LAS RCP

main flange bolting for the period of extended operation.

Based upon the above information, the staff finds that the applicant has provided an acceptable

AMP for managing loss of material of LAS RCP main flange bolting for the period of extended

operation. Therefore, the staff's concern described in RAI 3.1.2-3 is resolved.

In LRA Table 3.1.2-3 the applicant identified that a loss of mechanical closure integrity is an

AERM for RCP components manufactured from LAS material and exposed to an externalambient environment. The applicant manages this aging effect using the Inservice Inspection,

Bolting and Torquing Activities, and Boric Acid Corrosion Prevention Programs. The applicant

identified the components requiring management as the main flange bolts. The aging effect,

material, and environment combination is consistent with the GALL Report, but the report

credits a different AMP. Item IV.C2.4-g of the GALL Report credits the Boric Acid Corrosion

Prevention Program and requires no further evaluation. The staff concludes that the Inservice

Inspection, Bolting and Torquing Activities, and the Boric Acid Corrosion Prevention Programs

will effectively manage the loss of mechanical closure integrity for Class 1 valve components

manufactured from LAS.

On the basis of the above information, the staff finds that the applicant has provided an

acceptable aging management program for managing loss of mechanical closure integrity for

Class 1 valve components manufactured from LAS.

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 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

AERMs for the pressurizer. The applicant identified the following programs that manage the

AERMs for the pressurizer and associated pressure boundary components:

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* - Water Chemistry Control Program

* Pressurizer Examinations Program

* Inservice Inspection-ASME Section Xl, Subsection IWB, IWC, and IWD Program

Boric Acid Corrosion Prevention Program

Alloy 600 Aging Management Program

* Bolting and Torquing Activities Program

In Table 3.1.2-4 of the LRA, the applicant provided a summary of AMRs for the pressurizer and

associated pressure boundary components, and identified which AMRs it considered to be not

consistent with the GALL Report. These components include the pressurizer lower head, shell,

and upper shell; surge, spray, relief, and safety nozzles and their thermal sleeves; and a variety

of support plates, brackets and lugs.

Staff Evaluation

This section provides the results of the staff's evaluation of the applicant's AMR for the aging

effects and the AMPS credited for managing them for the pressurizer components. The staff

also reviewed the applicable UFSAR Supplements to ensure that the AMPs are adequately

described.

Loss of Material in Carbon Steel, Low Alloy Steel, and Low Alloy Steel Internally Clad with

Stainless Steel or Nickel Based Alloy (Weld Buttering) for Selected Pressurizer Components

Exposed Externally to Potentially Leaking Borated Water

Summary of Technical Information in the Application

The applicant identified in LRA Table 3.1.2-4 that loss of material is an AERM for the following

pressurizer components which are made of carbon steel, LAS, and LAS clad with stainless steel

or nickel-based alloy and which are potentially exposed externally to leaking borated water:

* lower head, shell, and upper head (LAS clad with stainless steel)

* surge, spray, relief, and safety nozzles (LAS clad with stainless steel and nickel-based

alloy)

* support skirt and flange (carbon steel)

* seismic lugs (LAS)

* valve support bracket lugs (carbon steel)

* manway forging (LAS clad with stainless steel)

* manway cover and its bolts/studs (LAS)

The applicant credited the Boric Acid Corrosion Prevention Program (LRA Section B.1.4) with

the management of the loss of material in these components.

Staff Evaluation

The applicant identified the loss of material as an applicable aging effect for-carbon steel, LAS,-

and LAS clad with stainless steel or nickel-based alloy pressurizer components that are

exposed to the ambient environment. It characterized the AMR for managing these

components as not consistent with the GALL Report line item or not consistent with the GALL

Report line item except for the component itself.

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The Boric Acid Corrosion Prevention Program is used to manage the aging of carbon steel and

LAS SCs and electrical components onto which borated water may leak. The staff evaluation

and acceptance of this program can be found in SER Section 3.0.3.2.1. Using provisions in the

Boric Acid Corrosion Prevention Program for inspecting, detecting, or monitoring degradation of

SCs exposed to boric acid leakage to manage the loss of material in SCs that may be

potentially exposed externally to leaking borated water is consistent with GALL Report line

items for these listed components. Therefore, this approach is acceptable to the staff. Hence,

the staff finds that the applicant's AMR evaluation is consistent with the GALL Report, and 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 for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Cracking in Nickel-Based Alloy Weld in Surge, Spray, Relief, and Safety Nozzles and Surge and

Spray Nozzle Thermal Sleeves Under Borated Water Environment

Summary of Technical Information in the Application

The applicant identified that PWSCC cracking is an AERM for nickel-based alloy welds in

surge, spray, relief, and safety nozzles and surge and spray nozzle thermal sleeves that are

exposed to a borated water environment, as indicated in LRA Table 3.1.2-4.

The applicant credited Water Chemistry Control Program (SER Section 3.0.3.2.15), the Alloy

600 Aging Management Program (SER Section 3.0.3.3.1), and the Inservice Inspection

Program (SER Section 3.0.3.1) with the management of PWSCC for surge, spray, relief, and

safety nozzles, and the Water Chemistry Control and Alloy 600 Aging Management Programs

for surge and spray nozzle thermal sleeves.

Staff Evaluation

The applicant identified PWSCC as an applicable aging effect for nickel-based alloy weld

pressurizer components that are exposed to a borated water environment. It characterized the

AMRs for managing these components as not consistent with the GALL Report line item for the

nozzles, and not consistent with the GALL Report line item, except for the use of a different

AMP, for thermal sleeves.

Since nickel-based alloy is used in the weld buttering (Alloy 82/182, 52/152), PWSCC is a

concern for welds in pressurizer surge, spray, relief, and safety nozzles. The applicant credited

the Water Chemistry Control, Alloy 600 Aging Management, and Inservice Inspection Programs

for the management of the PWSCC. In this determination, the applicant referenced GALL line

item IV.C2.5-k for pressurizer instrument penetrations with Alloy 600 material and adopted the

GALL Report recommended Inservice Inspection and the Water Chemistry Control Programs to

manage cracking in pressurizer surge, spray, relief, and safety nozzles under a borated water

environment. For this line item, the GALL Report further recommends that the applicant

provide a plant-specific AMP or participate in industry programs to determine an appropriate

AMP for managing PWSCC of Alloy 182 weld material. The applicant's Alloy 600 Aging

Management Program is this plant-specific AMP recommended by the GALL Report, and it

incorporates the industry effort in managing PWSCC generically.

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Therefore, the staff concludes that using the Water Chemistry Control, Alloy 600 Aging- - .

Management, and Inservice Inspection Programs to manage cracking in surge, spray, relief,

and safety nozzles, is consistent with the GALL Report recommendations for these components

and is acceptable.

The applicant credited the Water Chemistry Control and Alloy 600 Aging Management

Programs with the management of PWSCC in surge and spray nozzle thermal sleeves. Like

pressurizer nozzles discussed above, the applicant referenced GALL line item IV.C2.5-k for

pressurizer instrument penetrations with Alloy 600 material for surge and spray nozzle thermal

sleeves. However, instead of using the three AMPs recommended by the GALL Report for line

item IV.C2.5-k, the applicant adopted only the Water Chemistry Control and Alloy 600 Aging

Management Programs to manage cracking in pressurizer surge and spray nozzle thermal

sleeves under a borated water environment. Not using the Inservice Inspection Program

recommended for GALL line item IV.C2.5-k for thermal sleeves is acceptable because the

surge and spray nozzle thermal sleeves, which are mechanically connected to or welded to the

safe end of the nozzles, are inaccessible from outside of the nozzles for inspections. Further,

the ASME Code does not have inspection requirements for the pressurizer surge and spray

nozzle thermal sleeves. Therefore, the staff concludes that using only the Water Chemistry

Control and Alloy 600 Aging Management Programs to manage cracking in surge and spray

nozzle thermal sleeves is acceptable.

On the basis of its review, the staff finds that the applicant has adequately evaluated the

management of cracking in nickel-based alloy weld in surge, spray, relief, and safety nozzles

and surge and spray nozzle thermal sleeves under a borated water environment , as., , - - -,

recommended in the GALL Report. Since the applicant's AMR results are either consistent with

the GALL Report requirements or consistent with the GALL Reports requirements with an

acceptable exception;-the staff 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 for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Pressurizer Summary of Aginq Management

The staff reviewed LRA Table 3.1.2-4, which summarized the results of AMR evaluations in the

SRP-LR for the pressurizer component groups.

In the LRA, the applicant stated that it will manage the loss of material for LAS clad with

stainless steel in treated, borated water using only the Water Chemistry Control-Primary and

Secondary Water Chemistry Control Program (CNP AMP B.1.40.1). Section 3.0.3.2.15 of this

SER documents the staff's evaluation of this program. This program applies to the lower head,

shell, upper head, surge, spray, relief, and safety nozzles (with nickel-alloy weld buttering), as

well as the manway forging.

Industry experience has shown that the effects of general and crevice corrosion, as well as

pitting, on cladding made of stainless steel in chemically treated, borated water are not

significant. On this basis, the staff finds that the management of this aging effect using water

chemistry control is sufficient.

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In the LRA, the applicant stated that it will manage the loss of material from stainless steel

components in treated, borated water using only the Water Chemistry Control Program. This

program includes the following:

* surge, spray, relief, and safety nozzle safe ends

* surge and spray nozzle thermal sleeves

* heater well nozzles and couplings

* immersion heater sheaths

* heater support plates, plate brackets, and plate bracket bolts

* spray head locking bar and couplings

* instrument nozzles and couplings, as well as the manway insert.

The loss of material from the CASS spray head in this environment is managed in the same

way.

On the basis of industry experience that the effects of general and crevice corrosion, as well as

pitting, on components made of stainless steel (including CASS) in chemically treated, borated

water are not significant, the staff finds that the management of this aging effect using water

chemistry control is sufficient.

In the LRA, the applicant stated that it will manage the cracking of the heater support plates,

their brackets, and the bracket bolts using the Water Chemistry Control Program. Although the

applicant cited a precedent, the staff was unable to confirm its applicability. For the component

referenced, the GALL Report recommends the use of the Inservice Inspection Program, in

addition to the Water Chemistry Control Program.

The staff asked the applicant to justify the absence of an inspection or monitoring program to

manage cracking of these components, or to identify the program it uses to accomplish this

task. By letter dated August 20, 2004, the staff asked, in RAI 3.1.3-2, that the applicant explain

the rationale for excluding the cracking of heater support plates, their brackets, and the bracket

bolts from the scope of an inspection or monitoring program, or to identify the program it uses

to supplement water chemistry control.

In a letter dated September 2, 2004, in its response to RAI 3.1.3-2, the applicant stated that it

credited the Water Chemistry Control and Inservice Inspection Programs to manage cracking of

the pressurizer heater sheaths and sleeves, which are the pressure boundary components that

are comparable to those in the GALL Report, Volume 2. The pressurizer heater support plates,

brackets, and bracket bolts are internal to the pressurizer; they provide lateral support for the

heaters and do not have a pressure boundary function.

On the basis of its review of the applicant's response to RAI 3.1.3-2, the staff finds that the

applicant will adequately manage the cracking of heater support plates, their brackets, and the

bracket bolts using only the Water Chemistry Control Program because these components do

not have a pressure boundary intended function and only require management using a

mitigative program, such as water chemistry control. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant will manage this aging effect

adequately during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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In the LRA, the applicant stated that it manages the cracking of LAS and carbon steel

components exposed to ambient air using the Inservice Inspection Program for the support skirt

and flange, seismic lugs, and valve support bracket lugs. The staff found this to be consistent

with the GALL Report and therefore acceptable.

In the LRA, the applicant stated that it manages cracking of the LAS manway cover bolts/studs

in ambient air using the Inservice Inspection Program. Although the applicant cited a

precedent, the staff was unable to determine its applicability. For the component referenced,

the GALL Report recommends the use of a program consistent with the Bolting Integrity

Program (i.e., GALL AMP Xl.M18).

The staff asked the applicant to explain its rationale for excluding this bolting material from the

scope of the Bolting and Torquing Activities Program (CNP AMP B.1.2) or to confirm that it is

managed using this program. By letter dated August 20, 2004, the staff asked, in RAI 3.1.3-1,

that the applicant explain its rationale for excluding LAS manway cover bolts/studs in ambient

air from the scope of CNP AMP B.1.2 or confirm that it is managed using this program.

In a letter dated September 2, 2004, in response to RAI 3.1.3-1, the applicant stated that it

credited the Bolting and Torquing Activities Program for managing loss of mechanical closure

integrity for LAS manway cover bolts/studs in ambient air in LRA Table 3.1.2-4. The applicant

also stated that the aging effect of cracking is listed separately for these same components and

is managed by the Inservice Inspection Program, which is more appropriate for closure bolting

in Class I systems.

On the basis of its review of the applicant's response to RAI 3.1.3-1, the staff finds that the

applicant will adequately manage all aging effects on bolting material for LAS manway cover

bolts/studs in ambient air using the Inservice Inspection and Bolting and Torquing Activities

Programs. The staff further concludes that there is reasonable assurance that the applicant will

adequately manage these aging effects during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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

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 Application

In LRA Section 3.1.2.1.5 and Table 3.1.2-5, the applicant stated that the steam generator

components are fabricated from carbon steel, LAS, LAS clad with stainless steel, LAS clad with

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nickel-based alloy, stainless steel, and nickel-based alloy. The nickel-based alloys are

thermally treated Alloy 690 tubing and Alloy 52/152 weld metal. In Section 3.1.2.1.5 and Table

3.1.2-5 of the LRA, the applicant stated that the components are exposed to treated, borated

water, treated water (secondary side), and external-ambient environments. The treated,

borated water and treated water environments include steam. The external environment has

the potential for limited periods of leaking borated water and steam. Table 3.0-1 of the LRA

defines these environments.

In Table 3.1.2-5 of the LRA, the applicant identified the aging effects listed below for the steam

generator components requiring AMPs specified in the GALL Report:

* cracking of the following component types exposed to borated water (primary

side)-primary head, primary nozzles, primary nozzle safe ends, partition plates and

nozzle dam retention rings, primary manway insert plates, tubes and tube plugs, and

tubesheet

* cracking of the following component types exposed to the containment ambient

atmosphere with periodically leaking boric acid and steam-primary manway closure

bolting and secondary manway, handhole, recirculation (Unit 1), and inspection port

closure bolting

* cracking of the following component types exposed to treated water (secondary

side)-tubes and tube plugs; lower shell, upper shell, transition cone, steam drum, and

elliptical upper head; feedwater nozzles; feedwater nozzle thermal sleeve (Unit 1); main

steam nozzles; feedwater safe ends (Unit 1); secondary blowdown and instrumentation

connections, recirculation connections (Unit 1), and secondary shell drain connections

(Unit 2); secondary handhole ports and inspection ports; secondary manways; steam

flow restrictors (Unit 1); feedwater elbow thermal liners (Unit 2) and feedwater liner

piston rings (Unit 2); tube wrappers (shroud); tube support plates and antivibration bars

(AVBs) (Unit 2); tube support plate stayrod nuts (Unit 2); tube support plate stayrod

washers and AVB retaining rings (Unit 2); lattice grid ring studs (Unit 1); and lattice grid

bars, U-bend flat bars, and J-tabs (Unit 1)

* loss of material of the following components exposed to borated water-primary head,

primary nozzles, primary nozzle safe ends, partition plates and nozzle dam retention

rings, primary manway insert plate, tubes and tube plugs, and tubesheet cladding

* loss of material of the following components exposed to the containment ambient

atmosphere with periodically leaking boric acid and steam-primary head; primary

nozzles; primary manway cover; primary manway closure bolting; tubesheet; lower shell,

upper shell, transition cone, steam drum, and elliptical upper head; feedwater nozzles;

main steam nozzles; secondary blowdown and instrumentation connections,

recirculation connections (Unit 1), and secondary shell drain connections (Unit 2);

secondary handhole ports and inspection ports; secondary handhole port covers,

inspection port covers, and recirculation port covers (Unit 1); secondary manways;

secondary manway covers; and secondary manway, handhole, recirculation (Unit 1),

and inspection port closure bolting

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-loss of material of the following components exposed to treated water (secondary.

side)-tubes and tube plugs; tubesheet; lower shell, upper shell, transition cone, steam

drum, and elliptical upper head; feedwater nozzles; feedwater nozzle thermal sleeve

(Unit 1); main steam nozzles; feedwater safe ends (Unit 1); secondary blowdown'and

instrumentation connections, recirculation connections (Unit 1), and secondary shell

drain connections (Unit 2); secondary handhole ports and inspection ports; secondary

handhole port covers, inspection port covers, and recirculation port covers (Unit 1);

secondary manways; secondary manway covers; steam flow restrictors (Unit 1);

feedwater elbow thermal liners (Unit 2) and feedwater liner piston rings (Unit 2); tube'

wrappers (shroud); tube support plates and AVBs (Unit 2); tube support plate stayrods

and tube support plate spacers (Unit 2); tube support plate stayrod nuts (Unit 2); tube'

support plate stayrod washers and AVB retaining rings (Unit 2); lattice grid ring and U-

- bend arch bars (Unit 1); lattice grid ring studs (Unit 1); and lattice grid bars, U-bend flat

bars, and J-tabs (Unit 1)

* loss of mechanical closure integrity for the following components exposed to thecontainment ambient atmosphere with periodically leaking boric acid and

steam-primary manway closure bolting and secondary manway, handhole recirculation

(Unit 1), and inspection port closure bolting

* loss of mechanical closure integrity for the following components exposed to treated

water (secondary side)-tube support stay rod nuts (Unit 2) and lattice grid ring studs

In Table 3.1.2-5 of the LRA, the applicant identified the AMPs listed below for managing the

aging effects applicable to the steam generator components during the period of extended

operation. The following program summaries are based on the information provided in

Appendix B to the LRA:

* -Alloy 600 Aging Management Program

* - Bolting and Torquing Activities Program

* Boric Acid Corrosion Prevention Program

* Flow-Accelerated Corrosion Program

* Inservice Inspection-ASME Section Xl, Subsection IWB, IWC, IWD Program

* Steam Generator Integrity Program

* Water Chemistry Control-Primary and Secondary Water Program

Staff Evaluation

In accordance with 1 OCFR 54.21 (a)(3), the staff reviewed the information in LRA Section 3.1,

Table 3.1.2-5, and Appendix B to determine if the applicant will adequately manage the effects

of aging so that the intended functions of the steam generator components will be maintained

consistent with the CLB throughout the period of extended operation. The staff also reviewed

the applicable UFSAR Supplements to ensure that the AMPs are adequately described.

Aging Effects -

The staff reviewed and evaluated the applicability of the aging effects listed in LRA Table

3.1.2-5 for the steam generator components within the scope of license renewal.

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In LRA Section 3.1.2.2.1, "Cumulative Fatigue Damage," the applicant described the TLAAs it

performed on components in the RCS pressure boundary. Section 4.7.5, "Steam Generator

Tubes-Flow-Induced Vibration," of the LRA addresses the TLAA for fatigue of the steam

generator tube bundles. In that section, the applicant stated that the analyses it performed on

the tube bundles in Units 1 and 2 steam generators meet the 10 CFR 54.3 definition of a TLAA, and that the analyses remain valid through the period of extended operation, in accordance with

10 CFR 54.21 (c)(1)(i).

Review of Aging Effects on Steam Generator Items in LRA Table 3.1.1

In Table 3.1.1 of the LRA, the applicant described its proposed management of aging in steam

generator components, including any further evaluation recommended in the SRP-LR. Table

3.1.1 of both the LRA and the SRP-LR summarize the following steam generator aging issues, which are evaluated in Chapter IV of the GALL Report.

* pitting and crevice corrosion of the steam generator shell assembly (Item 3.1.1-2) * erosion of feedwater impingement plate and support (Item 3.1.1-17) * -cracking and loss of material of tubes, repair sleeves, and plugs (Item 3.1.1-18) * FAC of carbon steel tube support lattice bars (Item 3.1.1-19) * ligament cracking of carbon steel tube support plates (Item 3.1.1-20) * FAC of feedwater inlet ring and supports (Item 3.1.1-21) * FAC of various steam generator components (Item 3.1.1-25) * loss of material, cracking, and loss of preload of closure bolting (Item 3.1.1-26) * boric acid corrosion of carbon steel RCPB external surfaces (Item 3.1.1-38) * erosion of secondary manways and handholds (Item 3.1.1-39) * SCC of upper and lower heads, tubesheets, primary nozzles, and safe ends (Item 3.1.1-

44)

The applicant stated that Items 3.1.1-17, 3.1.1-19, and 3.1.1-20 are not applicable because

CNP steam generators do not have feedwater impingement plates, carbon steel lattice bars, or

carbon steel tube support plates. The stainless steel tube support lattice bars in Unit 1 and

stainless steel tube support plates in Unit 2 are not susceptible to these aging mechanisms.

The applicant stated that Item 3.1.1-39, erosion of carbon steel manways and handholds, is not

applicable to the CNP recirculating steam generators because it applies only to once-through steam generators. The staff agrees that these four items are not applicable to CNP.

RAI 3. 1-1

With regard to Item 3.1.1-2, the applicant's plan is consistent with the GALL AMP for managing pitting and crevice corrosion of the shell assembly; however, the applicant did not discuss the

augmented inspection recommended by the GALL Report. By letter dated May 19, 2004, the

staff requested, in RAI 3.1-1, that the applicant describe the details of the augmented inspection for the shell assembly and explain this inspection's management of the aging effect

(Item 3.1.1-2 in Table 3.1.1). The aging effect is loss of material due to pitting and crevice

corrosion, which may not be detected by the Inservice Inspection and Water Chemistry Control

Programs. Section 3.1.2.2.2 of the SRP-LR recommends an augmented inspection for this

aging effect. The applicant stated that it will supplement the Water Chemistry Control Program with the Steam Generator Integrity Program for secondary-side components. However, the

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Steam Generator Integrity Program description, NEI 97-06, or the EPRI Steam Generator

Examination Guidelines do not include such an inspection.

In a letter dated August 11, 2004, the applicant responded that an augmented inspection is

necessary only if this aging effect is known to exist, and that the internal surfaces of the steam

generator shells at CNP have not experienced pitting corrosion. The applicant stated that

augmented inspections of the upper shell-to-transition cone girth welds would be added to the

Inservice Inspection Program as part of the assessment of degradation mechanisms and

industry operating events performed under the Steam Generator Integrity Program. Becausethe steam generator shells at CNP have not experienced pitting or crevice corrosion, and

augmented inspections will be added if the industry experiences pitting or crevice corrosion in

this area, the staff accepts the Water Chemistry Control and Steam Generator Integrity

Programs for managing aging of the shell assembly.

In Item 3.1.1-18, the applicant addressed the aging effects of cracking, loss of material, and

deformation of steam generator tubes, plugs, and sleeves. The aging effects include (1) crack

initiation and growth due to PWSCC, ODSCC, or IGA, (2) loss of material due to wastage and

pitting corrosion, (3) loss of material due to fretting or wear, and (4) deformation due to

corrosion at tube support plate intersections. Section 3.0.3 of this SER presents the staff's

evaluation of the aging management plan for these components. The staff concluded that the

applicant adequately evaluated these aging issues according to the GALL Report

recommendations. Therefore, the staff's concern described in RAI 3.1-1 is resolved

RAI 3.1-2

Item 3.1.1-21 addresses FAC of the steam generator feedwater inlet ring and supports. The

applicant omitted these components from the scope of license renewal on the basis that the

aging effect applies only to CE System 80 steam generators. However, the staff was aware

that J-nozzles at one plant had to be replaced in 1989 due to erosion-corrosion, and a leak

occurred at another plant at a previously plugged bottom spray hole in 1995. Therefore, in a'

letter dated May 19, 2004, the staff requested, in RAI 3.1-2, that the applicant explain how it will

manage the aging of the feedwater ring assembly, including the J-nozzles. In a letter dated

August 11, 2004, the applicant responded that these aging concerns do not apply because the

CNP steam generators have Alloy 690 J-tubes and do not have plugged bottom spray holes.

The staff accepts this justification, but the details will not be discussed here. In a separate -

letter dated May 20, 2004, responding to RAI 2.3.1.6-2 from the NRC Reactor Systems Branch

(SRXB), the applicant stated that the feedwater ring and J-tubes are not within the scope oflicense renewal because they do not directly support the steam generator pressure boundary

function, they are not required for mitigation or recovery from any DBEs or regulated events at

CNP, and systems of this design have experienced no failures. As discussed in Section 2.3.1.5'

of this SER, SRXB has concluded that the components are not within scope for the application.

The staff's concern described in RAI 3.1-2 is resolved.

Item 3.1.1-25 addresses FAC of various steam generator components, such as main steam

nozzles and Unit 2 feedwater elbow thermal liners. As recommended in the GALL Report, the

applicant manages aging of these components using the Flow-Accelerated Corrosion Program,

which is consistent with the program in the GALL Report. The applicant will supplement this

program with the Water Chemistry Control Program, which, with enhancements, will also be

consistent with the GALL Report for primary and secondary water chemistry. Feedwater

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nozzles are protected by nickel-based thermal sleeves (Unit 2) and carbon steel thermal liners

(Unit 1), which are evaluated in Table 3.1.2-5 and discussed below.

Item 3.1.1-26 addresses the loss of material (wear), the loss of preload (stress relaxation), and

crack initiation and growth (cyclic loading and/or SCC) in closure bolting for the RCPB,

including primary- and secondary-side steam generator closures. The SRP-LR and GALL

Report list the Bolting Integrity Program as the appropriate AMP for this aging issue. The

applicant plans to use ISI to manage loss of material and cracking for these components. The

applicant will manage the loss of mechanical closure integrity using the Bolting and Torquing

Activities, Inservice Inspection, and Boric Acid Corrosion Prevention Programs for steam

generator closures. The staff finds this combination of AMPs acceptable because they include

the same activities as the GALL program for which they substitute (i.e., Bolting Integrity

Program). The Bolting Integrity Program refers to ISI, inspection for leakage and corrosion,

and selection and installation of bolting material. Like the GALL report Bolting Integrity

Program, the applicant's Bolting and Torquing Activities Program relies on EPRI

recommendations. The GALL Report does not address corrosion and cracking of steam

generator bolting in the external-ambient environment (listed in LRA Table 3.1.2-5); however,

Section 3.0.3.3.2 of this SER does discuss this environment.

Item 3.1.1-44 addresses crack initiation and growth due to SCC, PWSCC, and IASCC of steam

generator upper and lower heads, tubesheets, primary nozzles, and safe ends. Except for the

tubesheet, the applicant manages these aging effects with the Alloy 600 Aging Management,

Inservice Inspection, and Water Chemistry Control Programs. These programs are consistent

with Chapter IV of the GALL Report, except for the Alloy 600 Aging Management Program

which is a new, plant-specific program that the applicant will implement before the period of

extended operation. However, the applicant will base this program on ASME Code Section XI

and will submit it to the staff for review and approval 2-3 years before the period of extended

operation. The staff therefore accepts the applicant's conclusion that this aging management

approach is consistent with the GALL Report and will effectively manage SCC, PWSCC, and

IASCC in these components. Table 3.1.2-5 addresses aging management for the tubesheet,

which is not listed in Chapter IV of the GALL Report. This issue is also discussed below.

Review of Aging Effects on Steam Generator Items in LRA Table 3.1.2-5

In LRA Table 3.1.2-5, the applicant indicated the steam generator aging effects that are

identified for aging management as a result of the applicant's license renewal review, but are

not addressed by the GALL Report. For some items, the staff requested additional information

from the applicant to perform a thorough evaluation. Those items are discussed below.

According to LRA Table 3.1.2-5, the applicant credited the Water Chemistry Control Program

(along with the Steam Generator Integrity Program in some cases) for managing the loss of

material and cracking during the extended operating period. This applies to the following

components managed for the loss of material:

* stainless steel cladding on the primary head in borated water

* stainless steel cladding on the primary nozzles in borated water

* stainless steel primary nozzle safe ends in borated water

* nickel-based alloy partition plates and nozzle dam retention rings in borated water

* nickel-based alloy and stainless steel primary manway insert plates in borated water

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* nickel-based alloy tubes and plugs in borated water and in treated water

* nickel-based alloy tubesheet cladding in borated water

* LAS tubesheet in treated water

* LAS feedwater nozzles in treated water

* nickel-based alloy feedwater nozzle thermal'sleeve (Unit 1) in treated water'

* nickel-based alloy feedwater safe ends (Unit 1) in treated water

* 'LAS blowdown, instrument, and other connections in treated water

* LAS handhole, inspection, and recirculation port covers in treated water

* stainless steel steam flow restrictors (Unit 1) in treated water

* nickel-based alloy feedwater liner piston rings (Unit 2) in treated water

* carbon steel tube wrappers (shroud) in treated water

* stainless steel tube support plates and antivibration bars (Unit 2) in treated water

* carbon steel tube support plate stayrods, spacers (Unit 2), and stayrod nuts in treated

water

* nickel-based alloy tube support plate stayrod washers and AVB'retaining rings (Unit 2)

in treated water

* carbon steel lattice grid rings, lattice grid ring studs (Unit 1), and U-bend arch bars (Unit

1) in treated water

* -stainless steel lattice grid bars, U-bend flat bars, and J-tabs' (Unit 1) in treated water

It also applies to the following components managed for cracking:

* carbon steel tube wrappers (shroud) in treated water

* stainless steel tube support plates and antivibration bars (Unit 2) in treated water

* carbon steel tube support plate stayrod nuts (Unit 2) in treated water

* nickel-based alloy tube support plate stayrod washers and AVB retaining rings (Unit 2)

in treated water

* carbon steel lattice grid ring studs (Unit 1) in treated water

* stainless steel lattice grid bars, U-bend flat bars, and J-tabs (Unit 1) in treated water

RAts 3.1-3 and 3.1-4

The staff considered the applicant's discussion incomplete for the components listed above

because water chemistry control is a preventive strategy, and the Steam Generator Integrity

Program does not specify how to detect these aging effects. Therefore, by letter dated May 19,

2004, the staff requested, in RAls 3.1-3 and 3.1-4, that the applicant identify the aging

mechanisms for these components and describe how it would detect and monitor the loss of

material or cracking, if prevention fails. (Section 3.0.3.1 of this SER evaluates the Steam

Generator Integrity Program.)

In a letter dated August 11, 2004, the applicant responded that it would maintain the water

chemistry according to the EPRI Primary Water Chemistry Guidelines to manage general,

pitting, and crevice corrosion of stainless steel and nickel-based components exposed to

borated (primary) water. These guidelines limit oxygen to'less than 100 parts per billion (ppb),

and chloride, fluoride, and sulfate concentrations to less than 150 ppb each. The staff has

reviewed these guidelines and confirmed the limits,':as well as the fact'that stainless steel and

the relevant nickel-based alloys resist corrosion in this environment. 'The staff finds the -

applicant's primary water chemistry control approach acceptable for managing general, pitting,

*and crevice corrosion of these stainless steel and nickel-based primary-side components. -

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To prevent crevice corrosion and cracking of carbon steel, LAS, stainless steel, and nickelbased steam generator internals exposed to treated (secondary) water, the applicant stated, in

a letter dated August 11, 2004, that it would maintain secondary water chemistry consistent with

EPRI Secondary Water Guidelines. In the August 11, 2004, letter, and in a letter dated August

19, 2004, the applicant responded to RAI 3.1-4 (and the related RAI B.1.31-1) by explaining

that all secondary-side internals that form the tube support structure are within the scope of

secondary-side visual inspection under the Steam Generator Integrity Program. The applicant

also stated that these components are representative of components inspected visually as part

of the Steam Generator Integrity Program (CNP AMP B.1.31). The applicant stated that it

completes a steam generator degradation assessment before these inspections to focus the

inspections adequately on the expected degradation mechanisms. Based on this assessment,

the applicant performs visual examinations of the secondary-side internal components included

in LRA Table 3.1.2-5 to detect degraded conditions. If degraded conditions are found, the

applicant documents the condition through the Corrective Action Program and expands the

inspection scope in the area of interest until the condition is bounded. The applicant identified

the major focus areas as the tubesheet region, tube support structures, U-bend region, and

feedwater distribution system.

In a public meeting on September 1,2004, documented as a follow-up to RAI 3.1-1 in a letter

dated September 29, 2004, the staff requested the applicant to explain the frequency of the

steam generator secondary-side inspections. By letter dated October 18, 2004, the applicant

stated that the interval for secondary side visual inspections is no more than two operating

cycles. The scope of the inspections is based on plant-specific degradation assessments that

consider operating experience at CNP and with other steam generators of similar design. The

staff concludes that this is acceptable because these components are subject to inspection

under the Steam Generator Integrity Program. In addition, the frequency of inspection is a

maximum of every second outage, degradation assessments are performed prior to the

inspection to focus inspections on susceptible locations, and no degradation problems have

occurred to date with the replacement steam generators. The staff therefore concludes that

both the Water Chemistry Control and Steam Generator Integrity Programs effectively manage

cracking of the listed components. Hence, the staff's concerns described in RAls 3.1-3 and

3.1-4 are resolved.

RAI 3.1-5

According to LRA Table 3.1.2-5, the applicant credited the Water Chemistry Control and Steam

Generator Integrity Programs for managing the fouling of tubes. In a letter dated May 19, 2004,

the staff requested, in RAI 3.1-5, that the applicant describe how it would detect and monitor

the fouling, if prevention fails. In a letter dated August 11, 2004, the applicant responded that

fouling of steam generator tubes is the result of corrosion product accumulation on the tube

surfaces (primarily the tube exterior surface), which reduces the ability of the tubes to transfer

heat. The Water Chemistry Control-Primary and Secondary Water Chemistry Control

Program is a mitigation program that maintains an environment in which corrosion products are

limited to minimize aging effects. As part of the Steam Generator Integrity Program, the

applicant performs sludge lancing to remove bulk materials from the secondary side of the

steam generators and visual inspections of the tubes to access deposit buildup. Based upon

the inspection findings, the applicant initiates and develops mitigation strategies (e.g., bundle

flushing, chemical cleaning) through its Corrective Action Program, as required to ensure

continued operation without a performance (heat transfer) penalty. The staff finds that the

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applicant adequately addressed the possibility of tube fouling because the Steam Generator

Integrity Program and, if necessary, the Corrective Action Program includes cleaning of the

tubes. Therefore, the staff's concern described in RAI 3.1-5 is resolved.

RAI 3.1-6

Table 3.1.2-5 of the LRA lists both the loss of material and cracking as aging mechanisms forcarbon steel closure bolts in the external-ambient environment (page 3.1-90). -The staff noted

that it is unusual for cracking, especially SCC, to occur in a particular alloy in the same

environment that causes substantial general corrosion: Therefore, by letter dated May 19, --

2004, the staff requested, in RAI 3.1-6, that the applicant identify the mechanisms and specific

environments causing these aging effects.

In a letter dated August 11, 2004, the applicant stated that the bolting associated with the

steam generator manways and inspection ports is fabricated from SA-1 93 Grade B7 material,

which is susceptible to SCC and fatigue cracking. Although these fasteners are not.

intentionally exposed to water or steam, inadvertent exposure may result if leaks occur. If

leakage is combined with contaminant species, such as sulfides or chlorides, an aggressive

environment that can promote SCC may result. Therefore, cracking of the steam generator

bolting is considered an AERM for the period of extended operation. While the external

surfaces of the steam generators and bolting are not normally exposed to RCS fluid, the

potential for boric acid wastage exists because of leakage from the bolted closure. Therefore,

external surfaces of the steam generator closure bolts fabricated from ferritic steel are

potentially subject to the loss of material.

The response makes it clear that the bolting is high-strength steel and that the applicant is

considering two separate external environments that could potentially be present and could

degrade the bolts. Water or steam leaks could create an environment that causes SCC, while

leakage of RCS fluid could cause boric acid wastage. The applicant intends to manage boric

acid wastage with the Boric Acid Corrosion Prevention Program, as specified in the GALL

Report. The staff finds this acceptable for managing boric acid corrosion because the,

applicant's program is consistent with the GALL Report, which includes inspection of steam

generator closure bolting for boric acid corrosion through reference to GL 88-05. The applicant

intends to manage SCC, which is not an aging effect identified in the GALL Report for this

component, with the Inservice Inspection Program. The staff considers this acceptable

because the applicant's Inservice Inspection Program is consistent with GALL AMP XI.M1,

which includes inspection for cracking of pressure-retaining steam generator bolting.

Therefore, the staff's concern described in RAI 3.1-6 is resolved.

Aging Management Programs

In the LRA, the applicant stated that the primary head and primary nozzles of the steam

generator are fabricated from LAS clad with stainless steel. All are exposed to treated, borated

water. For these components, the applicant proposed to manage loss of material using only

the Water Chemistry Control-Primary and Secondary Water Chemistry Control Program (CNP

AMP B.1.40.1). Section 3.0.3.2.15 of this SER documents the staff's evaluation of this -

program, which is consistent with the GALL Report and therefore acceptable to the staff.

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In the LRA, the applicant stated that the primary. nozzle safe end and the primary manway

insert plate (Unit 2) are made of stainless steel and are exposed to treated, borated water.- For

these components, the applicant proposed to manage the loss of material using only the Water

Chemistry Control Program. This is consistent with the GALL Report and acceptable to the

staff.

In the LRA, the applicant stated that the partition plates, nozzle dam retention rings, primary

manway insert plate (Unit 1), and tube plugs are made of nickel-based alloy or LAS clad with

nickel-based alloy. The tubesheet (primary side) is LAS clad with nickel-based alloy. All are

exposed to treated, borated water. For these components, the applicant proposed to manage

the loss of material using only the Water Chemistry Control Program. This is consistent with

the GALL Report and acceptable to the staff.

In the LRA, the applicant stated that the feedwater nozzle thermal sleeve, feedwater safe ends

(Unit 1) and feedwater liner piston rings (Unit 2) are made of nickel-based alloy. All are

exposed to treated water. For these components, the applicant proposed to manage loss of

material using only the Water Chemistry Control Program. This is consistent with the GALL

Report and therefore acceptable to the staff.

In the LRA, the applicant stated that it manages cracking of the LAS lower shell, upper shell,

transition cone, steam drum, elliptical upper head, feedwater nozzle and main steam nozzle,

secondary blowdown and instrumentation connections, recirculation connections (Unit 1),

secondary shell drain connections, secondary handhole, and inspection ports in treated water

using the Inservice Inspection-ASME Section Xl, Subsection IWB, IWC, and IWD Program

(CNP AMP B.1.14). Section 3.0.3.1 of this SER documents the staff's evaluation of this

program.

RAI 3.1.3-4

The applicant made reference to a previously approved staff position, however, the case cited

credits a water chemistry control program, as well. The applicant did not identify the Water

Chemistry Control Program for managing this aging effect. The staff asked the applicant to

provide the basis for concluding that water chemistry control is not required or to identify the

water chemistry control program that it will use. By letter dated August 20, 2004, the staff

asked, in RAI 3.1.3-4, that the applicant explain the rationale for excluding a water chemistry

control program for managing cracking of the above components in treated water, or to identify

the water chemistry control program that it will use.

In a letter dated September 2, 2004, in its response to RAI 3.1.3-4, the applicant stated that

because the components are fabricated of LAS exposed to a treated water environment, they

are susceptible to the loss of material, which is managed by the Water Chemistry Control

Program. These components are also susceptible to cracking from metal fatigue, which is a

TLAA, and cracking from growth of preservice flaws, which is managed by the Inservice

Inspection Program and not mitigated by water chemistry control.

On the basis of its review of the applicant's response to RAI 3.1.3-4, the staff finds that the

applicant will adequately manage cracking and the loss of material of LAS components

exposed to a treated water environment using both the Inservice Inspection and Water

Chemistry Control Programs. On the basis of its review, the staff concludes that the applicant

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will adequately manage this aging effect during the period of extended operation, as required

by 10 CFR 54.21(a)(3).

In the LRA, the applicant stated that it will manage cracking of nickel-based alloy in treated

water for the feedwater nozzle thermal sleeve, feedwater safe end (Unit 1), and feedwater linerpiston rings (Unit 2) using the Water Chemistry Control and Inservice Inspection Programs.

The staff finds this to be acceptable.

In the LRA, the applicant stated that it manages the cracking of carbon steel in treated water for

the secondary manway and the feedwater elbow thermal liner (Unit 2) using the Inservice

Inspection Program. The applicant made reference to a previously approved staff position,

however, the case cited credits a water chemistry control program, as well. The applicant did

not identify the Water Chemistry Control Program for managing this aging effect.

The staff asked the applicant to provide the basis for concluding that water chemistry control is

not required or to identify the water chemistry control program that it will use. By letter dated

August 20, 2004, the staff asked; in RAI 3.1.3-4, that the applicant explain its rationale for

excluding a water chemistry control program for managing cracking of the above components in

treated water, or to identify the water chemistry control program that it will use.

In a letter dated September 2, 2004, in its response to RAI 3.1.3-4, the applicant stated that

because the components are fabricated of carbon steel exposed to a treated water

environment, they are susceptible to the loss of material, which is managed by the Water

Chemistry Control Program. These components are also susceptible to cracking from metal

fatigue, which is a TLAA, and cracking from growth of preservice flaws, which is managed by

the Inservice Inspection Program and not mitigated by water chemistry control.

On the basis of its review of the applicant's response to RAI 3.1.3-4, the staff finds that the

applicant will adequately manage cracking and loss of material of carbon steel components

exposed to a treated water environment using both the Inservice Inspection and Water

Chemistry Control Programs. Therefore, the staff's concern described in RAI 3.1.3-4 is

resolved. On the basis of its review, the staff concludes that the applicant will adequately

manage this aging effect during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

RAI 3.1.3-1

In the LRA, the applicant stated that it manages the cracking of carbon steel bolting of the

secondary manway, handhole, recirculation port (Unit 1), and inspection port closure in ambient

air using the Inservice Inspection Program. Although the applicant cited a precedent, the staff

was unable to confirm its applicability. For the component referenced, the GALL Report

recommends the use of a program consistent with the Bolting Integrity Program (GALL AMP

XLI.M18).

By letter dated August 20, 2004, the staff asked, in RAI 3.1.3-1, that the applicant explain its

rationale for excluding carbon steel bolting of the secondary manway, handhole, recirculation

port (Unit 1), and inspection port closure in ambient air from the scope of its Bolting and

Torquing Activities Program (CNP AMP B.1.2) or to confirm that it uses this program to manage

the aging effect.

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In a letter dated September 2, 2004, in response to RAI 3.1.3-1, the applicant stated that it

credited the Bolting and Torquing Activities Program for managing the loss of mechanical

closure integrity for the carbon steel bolting of the secondary manway, handhole, recirculation

port (Unit 1), and inspection port closure in ambient air in LRA Table 3.1.2-5. The applicant also stated that it listed the aging effect of cracking for these same components because it uses

the Inservice Inspection Program, which is more appropriate for closure bolting in Class I

systems, to manage this aging effect.

On the basis of its review of the applicant's response to RAI 3.1.3-1, the staff finds that the

applicant will adequately manage all aging effects of bolting material for carbon steel bolting of

the secondary manway, handhole, recirculation port (Unit 1), and inspection port closure in

ambient air by use of the Inservice Inspection and Bolting and Torquing Activities Program. Therefore, the staff's concern described in RAI 3.1.3-1 is resolved. On the basis of its review, the staff concludes that the applicant will adequately manage these aging effects during the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

In the LRA, the applicant stated that it will manage the loss of material from the stainless steel

steam flow restrictors (Unit 1) in treated water using the Water Chemistry Control Program.

In the LRA, the applicant stated that it will manage cracking of the stainless steel steam flow

restrictors (Unit 1) in treated water using the Water Chemistry Control and Inservice Inspection Programs. During the audit, the staff asked the applicant how it would perform such an

inspection. By letter dated April 23, 2004, the applicant stated that ISI should not be credited

for the steam flow restrictors. On the basis of industry and plant-specific operating experience, the staff concludes that the Water Chemistry Control Program will be acceptable for managing cracking of the steam flow limiter.

The staff evaluated all other assigned AMRs in Tables 3.1.2-1 through 3.1.2-5 of the LRA. The

staff evaluated those that were not accepted, as reviewed and documented above, and Section

3.0 of this SER discusses those that are related to the CNP LRA.

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 components 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 it will

adequately manage the effects of aging for the reactor vessel, internals, RCS, pressurizer, and

steam generator components and component types that are within the scope of license renewal

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and subject to an AMR so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).--

3.2 Aging Management of Engineered Safety Features Systems

This section of the Safety Evaluation Report (SER) documents the staff's review of the

applicant's Aging Management Review (AMR) results for the Engineered Safety Features (ESF)

systems components and component groups associated with the following systems:

* ~~*'containment spray system

* containment isolation system

* emergency core cooling system

* containment equalization/hydrogen skimmer 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 2.3.2-4. The applicant

also listed the materials, environments, AERMs, and AMPs associated with each system.

In Table 3.2.1, "Summary of Aging Managemnent 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 ESF 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 the GALL Report recommends

further evaluation.

3.2.2 Staff Evaluation

The staff reviewed Section 3.2 of the LRA to understand the applicant's review process and to

determine whether the-applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the ESF system components that are within the

scope of license renewal and subject to an AMR 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 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 verify that

the material presented in the LRA is applicable and that the applicant identified the appropriate

GALL Report AMRs. Section 3.2.2.1 of this SER presents the staff's audit and review findings.

The staff also audited and reviewed those AMRs that are consistent with the GALL Report and

for which further evaluation is recommended. The staff verified that the applicant's additional

evaluations are 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.

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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 appropriate aging effects 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 UFSAR Supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

ESF systems components and component groups.

Table 3.2-1 below summarizes 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 of Engineered Safety Feature Components in the GALL

Report

Component Aging Effectl AMP in GALL: AMP in LRA Staff''

Group: Mechanism Report.-.' '- .. Ealuto

Piping, fittings, and Cumulative fatigue TLAA, evaluated in TLAA Consistent with

valves in the ECCS damage accordance with GALL, which

(Item Number 10 CFR 54.21(c) recommends further

3.2.1-1) evaluation (See Section 3.2.2.2.1)

Components in Loss of material due Plant specific System Walkdown Consistent with

containment spray to general corrosion Program (B.11.38) GALL, which

(PWR only), recommends further

standby gas evaluation (See

treatment (BWR Section 3.2.2.2.2) only), containment

isolation, and

ECCS (Item Number 3.2.1-3) .

Components in Loss of material due Plant specific Water Chemistry Consistent with

containment spray to pitting and crevice Control Program GALL, which

(PWR only), corrosion (B.11.40); Wall recommends further

standby gas Thinning Monitoring evaluation (See

treatment (BWR Program (B.1.39); Section 3.2.2.2.3) only), and ECCS Containment

(Item Number Leakage Rate

3.2.1-5) Testing Program

(B.1.8)

Containment Loss of material due Plant specific Water Chemistry Consistent with

isolation valves to MIC Control Program GALL, which

and associated (B.1.40); Wall recommends further

piping (Item Thinning Monitoring evaluation (See

Number 3.2.1-6) Program (B.1.39); Section 3.2.2.2.4)

Containment

Leakage Rate

Testing Program (B.1 .8)

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Component Aging Effect/'- AMP in GALL AMP in LRA Staff

-Group-- ... , Mechanism Repot -Evaluation

High-pressure Local loss of 7 Plant specific - System Testing Consistent with

safety injection material due to Program (B.1.37) GALL, which

(charging) pump erosion recommends further

miniflow orifice evaluation '(See

(Item Number Section 3.2.2.2.6)

3.2.1-8)

External surface of Loss of material due Plant specific System Walkdown Consistent with

carbon steel to general corrosion Program (B.1.38) GALL, which

components (Item recommends further

Number3.2.1-10) evaluation (See

Section 3.2.2.2.2)

Piping and fittings Loss of fracture Thermal aging Not applicable Consistent with

of CASS in the toughness due to embrittlement of GALL, which

ECCS (Item thermal aging CASS recommends no

Number 3.2.1 -11) embrittlement further evaluation

(See Section'

'_ 3.2.2.1)

Components Loss of material due Open-cycle cooling Service Water Consistent with

serviced by open-, to general, pitting, water system Syste'm Reliability GALL, which'

cycle cooling and crevice Program (B.1.29); recommends no

system (Item corrosion, MIC, and Heat Exchanger further evaluation

Number 3.2.1-12) biofouling; buildup of Monitoring Program (See Section

deposit due to (B.1.13) 3.2.2.1)

biofouling .

Components Loss of material due Closed-cycle Water Chemistry Consistent with

serviced by closed- to general, pitting, cooling water Control-Closed GALL, which

cycle cooling and crevice system Cooling Water recommends no

system (Item corrosion Chemistry Control further evaluation

Number 3.2.1-13) Program (B.1.40.2); (See Section

Heat Exchanger 3.2.2.1)

Monitoring Program

(B.1.13) _

Pumps, valves, Crack initiation and Water chemistry Water Chemistry Consistent with

piping, and fittings, growth due to SCC Control Program GALL, which

and tanks in (B.1.40) recommends no

containment spray further evaluation

and ECCS (Item (See Section

Number 3.2.1 -15) 3.2.2.1)

Carbon steel Loss of material due Boric acid corrosion Boric Acid ' Consistent with

components (Item to boric acid Corrosion GALL, which

Number 3.2.1-17) corrosion Prevention Program recommends no

(B.1.4) further evaluation

(See Section

_ ._ _3.2.2.1)

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-Component; Aging Effect! AMP in GALL . -AMP in LRA! Staff

Group- Mechanism Report -: . .*. Evaluation.

Closure bolting in Loss of material due Bolting integrity Bolting and Consistent with

high-pressure or to general corrosion; Torquing Activities GALL, which

high-temperature crack initiation and Program (B.1.2); recommends no

systems (Item growth due to cyclic Boric Acid further evaluation

Number 3.2.1-18) loading and/or SCC Corrosion (See Section

Prevention Program 3.2.2.1)

(B.1.4); System

Walkdown Program

(B.1.38)

The staff's review of the ESF system components 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 systems 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 systems 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 review of the AMR results for components in

the ESF systems 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 presents the staff's review of AMPs

that are credited with managing or monitoring aging effects of the ESF systems components

and associated components.

3.2.2.1 Aging Management Evaluations That Are Consistent with the GALL Report, for Which

No Further Evaluation Is Required

Summary of Technical Information in the Application

In Section 3.2.2.1 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

ESF system components:

* Boric Acid Corrosion Prevention Program

* Heat Exchanger Monitoring Program

* Inservice Inspection-ASME Section Xl, Augmented Inspections Program

* Service Water System Reliability Program

* System Walkdown Program

* Water Chemistry Program

*2 Bolting and Torquing Activities Program

* Containment Leakage Rate Testing Program

* Wall Thinning Monitoring Program

* Oil Analysis Program

* Preventive Maintenance Program

* System Testing Program

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Staff Evaluation

In Tables 3.2.2-1 through 3.2.2-4 of the LRA, the applicant summarized 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 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 bounds the plant-specific components contained in these GALL Report component

groups.

The applicant provided a note for each AMR line item. The notes describe the alignment of the

information in the tables with the information in the GALL Report. The staff audited those

AMRs with notes A-through E, where applicable, which indicate that the AMR is consistent with

the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that 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 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 is applicable 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

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component is applicable to the component under review. The staff verified whether

the staff 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.

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Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but a different AMP is credited. The staff audited these line

items to verify consistency with the GALL Report. The staff also determined whether the

identified AMP would manage the aging effect consistent with the AMP identified 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

basis 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

consistent with the GALL Report, are indeed 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 it will adequately manage the effects of aging 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

The staff has verified the applicant's claim of consistency with the GALL Report. The staff has

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 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 it will adequately manage the effects of aging for these

components 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).

3.2.2.2 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 3.2.2.2 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

* changes in properties due to elastomer degradation

* local loss of material due to erosion

* buildup of deposits due to corrosion

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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 had adequately

addressed the issues that received additional evaluation. 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 staff'sauidit and review report presents details of this effort.

The GALL Report indicates that the aging effects described in the following sections should

receive further evaluation.

3.2.2.2.1 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.

3.2.2.2.2 Loss of Material due to General Corrosion

In LRA Section 3.2.2.2.2,-the applicant addressed the 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 the 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 adequate management of the aging effect.

The applicant stated in the LRA that it credits the plant-specific CNP AMP B.1.38, "System

Walkdown," 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 the containment spray system and the ECCS have no carbon steel

components. In LRA Table 3.2.1, Item 3.2.1-1 0, the applicant also stated that the System

Walkdown Program manages the loss of material due to general corrosion on external surfaces

of carbon steel components. The staff evaluation of this program appears in Section 3.0.3.3.14

of this SER.

On the basis of its review of the System Walkdown Program, the staff finds that the applicant

has appropriately evaluated AMR results involving management of the loss of material due to

general corrosion, as recommended in the GALL Report.

3.2.2.2.3 Local Loss of Material due to Pitting and Crevice Corrosion

In LRA Section 3.2.2.2.3, the applicant addressed the local loss of material from pitting and

crevice corrosion that could occur in the containment spray components, containment isolation

valves and associated piping, and ECCS.

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Section 3.2.2.2.3 of the SRP-LR states that the local loss of material from pitting and crevice

corrosion could occur in the containment spray components, containment isolation valves and

associated piping, and ECCS. The GALL Report recommends further evaluation to ensure

adequate management of the aging effect.

In the LRA, the applicant credited the Water Chemistry Control-Primary and Secondary Water

Chemistry Control (CNP AMP B.1.40.1), the Wall Thinning Monitoring (CNP AMP B.1.39), and

the Containment Leakage Rate Testing (CNP AMP B.1.8) Programs with managing the aging

effect of the loss of material due to pitting and crevice corrosion. The staff's evaluation of these

AMPs appears in Sections 3.0.3.2.15, 3.0.3.3.15, and 3.0.3.1 of this report, respectively.

Section 3.2.2.2.3.2 of the SRP-LR requires verification of the programs' effectiveness and

identifies one-time inspections as an acceptable verification method. The Wall Thinning

Monitoring Program includes periodic (rather than one-time) inspection of appropriately

selected sample components. This approach is acceptable to the staff.

On the basis of its review of the Water Chemistry Control, Wall Thinning Monitoring, and

Containment Leakage Rate Testing Programs, the staff finds that the applicant has

appropriately evaluated AMR results involving management of the loss of material due to pitting and crevice corrosion, as recommended in the GALL Report.

3.2.2.2.4 Local Loss of Material due to Microbiologically Influenced Corrosion

In LRA Section 3.2.2.2.4, the applicant addressed the local loss of material due to

Microbiologically Influenced Corrosion (MIC).

Section 3.2.2.2.4 of the SRP-LR states that the 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

adequate management of the aging effect.

The applicant in the LRA credited the Water Chemistry Control-Primary and Secondary Water

Chemistry Control (CNP AMP B.1.40.1), Wall Thinning Monitoring (CNP AMP B.1.39), and

Containment Leakage Rate Testing (CNP AMP B.1.8) Programs with managing the aging effect

of the loss of material due to MIC. The staff evaluation of these programs appears in Sections

3.0.3.2.15, 3.0.3.3.15, and 3.0.3.1 of this report, respectively.

On the basis of its review of the Water Chemistry Control, Wall Thinning Monitoring, and

Containment Leakage Rate Testing Programs, the staff finds that the applicant has

appropriately evaluated AMR results involving management of the loss of material due to MIC,

as recommended in the GALL Report.

3.2.2.2.5 Changes in Properties due to Elastomer Degradation

The applicant stated that this issue applies to BWRs only; therefore, it is not applicable to CNP.

The staff concurs.

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3.2.2.2.6 Local Loss of Material due to Erosion

In LRA Section 3.2.2.2.6, the applicant addressed the local loss of material due to erosion that

could occur in the high-pressure safety injection (HPSI) miniflow orifice.

Section 3.2.2.2.6 of the SRP-LR states that the 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 chemical and volume control systems. The

GALL Report recommends further evaluation to ensure adequate management of the aging

effect.

The applicant stated in the LRA that it uses the chemical and volume control charging pumps

and not the HPSI pumps for RCS makeup at CNP. The applicant credited the System Testing

Program (CNP AMP B.1.37) with managing this aging effect for the charging pump miniflow

orifice. The staff's evaluation of this program appears in Section 3.0.3.3.13.

On the basis of its review of the system testing program, the staff finds that the applicant has

appropriately evaluated AMR results involving management of the loss of material due to

erosion, as recommended in the GALL Report.

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 CNP.

The staff concurs.

3.2.2.2.8 Quality Assurance and 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 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 determines that the applicant has adequately

addressed the issues that have received further evaluation. In addition, the staff reviewed the

applicant's additional evaluations against the criteria contained in 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 it will adequately manage the effects of aging so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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

GALL Report

Staff Evaluation

The technical staff reviewed the AMR of the ESF component, material, environment, and AERM

combinations that are not addressed in the GALL Report and specific combinations addressed

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in the GALL Report that are within the scope of review. The AERM combinations not

addressed in the GALL Report use notes F through J in LRA Tables 3.2.2-1 through 3.2.2-4.

The staff verified 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 they adequately describe the programs.

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 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.

Aging Effects

Tables 3.2.2-1 through 3.2.2-4 of the LRA list 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 an AMR include bolting, tanks, thermowells, valves, and heat exchangers.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel components subject to an external air environment are subject to the aging

effects of loss of material and loss of mechanical closure integrity.

* Stainless steel components exposed to a raw and treated water environment are subject

to loss of material-wear.

* Stainless steel components exposed to a sodium hydroxide environment are subject to

cracking and loss of material.

* Stainless steel components exposed to treated and untreated borated water

environments are subject to the aging effects of cracking-fatigue and loss of material.

* Copper alloys exposed to external air and treated water environments are subject to the

aging effects of fouling and loss of material.

The staff reviewed the information in Sections 2.3.2.1 through 2.3.2.4 and Tables 3.2.2-1

through 3.2.2-4 in the LRA. During its review, the staff determined that it needed additional

information to complete its evaluation.

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By letter dated May 26, 2004, the staff requested that the applicant provide additional

information on the issues described in the system-specific RAls. By letter dated June 30, 2004,

the applicant responded to the RAls.- The following describes the responses to these RAls and

the staff's evaluation of the responses. This section presents those RAls and evaluations of the

applicant's responses that apply to several or all subsystems of the ESF system. Sections -

3.3.2.3.2 through 3.3.2.3.5 of this SER present the RAls specific to the subsystems and the

evaluation of the applicant's responses.

RAI 3.2-1

Table 3.2.1 and Section 3.2.2.2.1 of the LRA identify the applicant's aging management

approach for cumulative fatigue damage for components in the ESF systems. - In the

discussion, the LRA refers to a TLAA in Section 4.3, which states that the applicant determined

that components in the ECCS exceed the screening criteria. The applicant evaluated the piping

components that exceed the screening criteria for their potential to exceed 7000 thermal cycles

in 60 years of plant operation.

The applicant determined that none of the piping components in the ESF system exceed 7000

cycles during the period of extended operation. In RAI 3.2-1, the staff asked the applicant to

provide the highest estimated number of thermal cycles and the basis for derivation for each:

component type identified in Tables 3.2.2-1 through 3.2.2-4 of the LRA for which TLAA-Metal

Fatigue Program is the designated AMP. For those components whose material or aging effect

is not specified in the GALL Report (designated by notes F and I respectively), the staff asked

the applicant to clarify whether it performed the thermal cycle evaluation in accordance with the

SRP-LR, Section 4.3.1.1.2. If so, the applicant should state whether its TLAA program is -

consistent with the SRP-LR; if not, the applicant should explain any differences: The staff also

asked the applicant to address how it accounts for unanticipated transients and thermal

stratification where applicable in the estimation.

In its response, the applicant stated the following:

The evaluation of cracking by fatigue was identified as a time-limited aging

analysis (TLAA) for selected mechanical components in the containment

isolation system (LRA Table 3.2.2-2) and the emergency core cooling

system (ECCS) (LRA Table 3.2.2-3). Evaluation of cracking by fatigue was not

identified as a TLAA for components in the containment spray system

(LRA Table 3.2.2-1) or the containment equalization/hydrogen skimmer system":-

(LRA Table 3.2.2-4).

The applicant clarified that the containment isolation system mechanical components identified

as susceptible to cracking from fatigue in LRA Table 3.2.2-2 are limited to non-Class 1 RCS

sample line piping and valves associated with containment penetrations 1 -CPN-66 and

2-CPN-66, which were designed in accordance with United States of America Standard (USAS)

B31.1. License renewal drawings LRA-1-5141 and LRA-2-5141 show the'non-Class 1 sample -

line components associated with CPN-66. Section 4.3.2 of the LRA discusses the evaluation of

cracking by fatigue for the non-Class 1 portions of the sample line, which is the subject of RAI

4.3.2-1.

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The ECCS mechanical components identified as susceptible to cracking from fatigue in

LRA Table 3.2.2-3 include the non-Class 1 residual heat removal (RHR) heat exchanger

(HE-17) and RHR pump mechanical seal heat exchanger (HE-32) tubes; RHR pump (PP-35)

casings; and RHR system piping, thermowells, tubing, strainer housings, and valves, which are

subject to elevated temperatures when used during plant cooldown. License renewal drawings

LRA-1 -5135A, LRA-1 -5143, LRA-2-5135A, and LRA-2-5143 show these non-Class 1 RHR

components.

With regard to RHR piping, valves, and other mechanical components designed in accordance

with USAS B31.1, the RHR system is restricted to the 200 RCS heatup and cooldown cycles

shown in LRA Table 4.3-1. Therefore, RHR mechanical components will not approach

7000 cycles during the period of extended operation.

Section 4.3.2 of the LRA discusses fatigue of the RHR heat exchangers. The tube side of

these heat exchangers was designed in accordance with ASME Code, Section III, Class C, and

the shell side was designed in accordance with ASME Code, Section Vill, Division 1, for unfired

welded pressure vessels. The equipment specification for the RHR heat exchangers requires

the supplier to verify that all conditions of ASME Code, Section 1II, paragraph N-415.1 (i.e.,

exemption from fatigue for Class 1 components), are satisfied for the transient conditions listed

in the equipment specification. Specifically, the RHR heat exchangers must be capable of a

step change of tube-side fluid from 29 0C (85 OF) to 176 0C (350 OF) simultaneously with 200

cycles of pressurization to the heat exchanger's tube-side design pressure of 600 psig.

The design transients identified in the heat exchanger specification are consistent with the RCS

transients defined in UFSAR Table 4.1-10 for heatups and cooldowns. As described in LRA

Section 4.3.1, the assumed number of RCS design transients is acceptable for 60 years, and

the fatigue evaluation considered in the original design of the RHR heat exchangers will remain

valid during the period of extended operation in accordance with 10 CFR 54.21 (c)(11)(i).

The RHR pumps were designed in accordance with the Standard of the Hydraulic Institute,

USAS 616.5, and ASME Draft Code for Pumps and Valves-1968. There were no fatigue

requirements for the design of the RHR pumps, and fatigue is not a TLAA for these pumps.

Section 4.3.1.2, "Generic Safety Issue," of the SRP-LR discusses the effects of reactor coolant

environment on component fatigue life. The applicant stated that its review of the SRP-LR

determined that the generic safety issue (GSI) discussion in Section 4.3.1.2 does not apply to

the non-Class 1 portions of the ESF systems evaluated in LRA Section 3.2 because the scope

of the GSI is limited to Class 1 locations identified in NUREG/CR-6260. The thermal cycle

evaluations discussed in this RAI response pertain to those performed for USAS B3.1.1 piping,

as discussed in SRP-LR, Section 4.3.1.1.2, "ANSI B31.1."

The applicant performed the thermal cycle assessment for USAS B31.1 piping, as described in

Section 4.3.1.1.2 of the SRP-LR, for components that operate at temperatures that exceed the

screening criteria provided in LRA Section 4.3.2. In addition to considering the

10 CFR 54.21 (a) screening criteria, the applicant also screened each mechanical system

reviewed for the CNP integrated plant assessment to identify potential metal fatigue TLAAs.

This screening entailed identifying non-Class 1 components that may operate at temperatures

in excess of 104 0C (220 OF) for carbon steel or 132 OC (270 0F) for austenitic stainless steel

during normal or upset conditions. The applicant identified fatigue evaluations of components

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that exceed the screening criteria as TLAAs. These screening criteria are consistent with those

described in Section 4.3.2 of the LRA for St. Lucie Units 1 and 2.

The threshold value of 104 0C (220 OF) for thermal fatigue of carbon steel piping is based on an

initial ambient temperature of 21 0C (70 0F) with a minimum temperature differential of 65 0C

(150 OF). The threshold value of 132 0C (270 0F) for thermal fatigue of stainless steel piping is

based on an initial ambient temperature of 21 0C (70 IF) with a minimum temperature

differential of 93 0C (200 OF). These minimum temperature differentials-are based on industrysponsored investigations and evaluations of thermal fatigue in nuclear plant piping systems, as

presented in EPRI TR-104534.

The l&M responses to NRC Bulletin 88-08, 'Thermal Stresses in Piping Connected to Reactor

Coolant Systems" (LRA References 4.3-11 through 4.3-15), as summarized in LRA Section

4.3.1, address thermal stratification in Class 1 portions of systems attached to the RCS.

Section 4.1.4 of the UFSAR describes cyclic load considerations. Components of the RCS

were designed to withstand the effects of cyclic loads resulting from reactor system: -

temperature and pressure changes. Normal power changes, reactor trips, and startup and

shutdown operations introduce these cyclic loads. Table 4.1-10 of the UFSAR gives the

number of thermal and loading cycles used for design purposes. To provide a high degree of

integrity for the equipment in the RCS, the transient conditions selected for equipment fatigue

evaluation were based on a conservative estimate of the magnitude and frequency of the

temperature and pressure transients resulting from normal operation, normal and abnormal

load transients, and accident conditions. To a large extent, the specific transient operating

conditions considered for equipment fatigue analyses were based on engineering judgment and

experience. The transients chosen are representative of transients which prudently should be

considered to occur during plant operation and which are sufficiently severe or may occur

frequently enough to be of possible significance to component cyclic behavior. This

methodology does not account for unanticipated transients. If they occur, the Corrective Action

Program identifies them and evaluates their impact on design thermal and loading cycles.

The applicant also identified that the ESF AMR results do not include any Class 1 ESF piping

and this piping is included in the RCS pressure boundary. As such, fatigue analysis does not

apply to the ESF AMR. The staff finds the applicants response reasonable and acceptable

because the applicant has addressed the staff's concerns related to thermal cycle evaluation in

accordance with the SRP-LR, in a technically sound and satisfactory manner. Therefore, the

staff's concerns described in RAI 3.2-1 are resolved.

RAI 3.2-5

Table 3.2.2-2 of the LRA credits the CNP Bolting and Torquing Activities Program with

managing the loss of mechanical closure integrity of carbon steel and stainless steel bolts in an

external air environment. In RAI 3.2-5, the staff asked the applicant to discuss how it will.

manage cracking and loss of preload resulting in the loss of mechanical closure integrity. The

staff also asked the applicant to designate the inspection activities in its program that are _

equivalent to the appropriate ASME Code, Section Xl, requirements. In addition, the staff

asked the applicant to address how it will manage the aging effects for inaccessible bolts.

These include bolts such as those located in cavities or obstructed by other components and

devices.

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In its response, the applicant stated the following:

Stress corrosion cracking (SCC) occurs through the combination of high stress,

a corrosive environment, and a susceptible material (such as that used in highstrength bolts). CNP piping material specifications do not permit, nor have they

historically permitted, high-strength bolting in non-Class 1 systems. Proper

lubricants and sealant compounds are used to minimize the potential for SCC.

In the aging management reviews, sufficient stress to initiate SCC was assumed

if bolting was subject to a corrosive environment. Since bolted closures do not

contain high-strength bolting, are not submerged or exposed to lubricants

containing contaminants, and are exposed to ambient temperature rather than

high-temperature process fluids, cracking is not an aging effect requiring

management for non-Class 1 closure bolting in an external air environment.

Review of operating experience did not identify problems with cracking of carbon

or stainless steel bolting in air environments.

In regard to the loss of preload, the applicant stated, '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 does not occur."

In addressing the staff's concern about bolting inspection activities that are equivalent to the

applicable ASME Code, Section Xl requirements, the applicant stated the following:

The Bolting and Torquing Activities Program, Boric Acid Corrosion Prevention

Program, and System Walkdown Program manage loss of mechanical closure

integrity for closure bolting as described in LRA Sections B.1.2, B.1.4, and

B.1.38, respectively. Visual inspections of bolting for loss of material and loss of

mechanical closure integrity in the Boric Acid Corrosion Prevention Program and

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 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 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 does not occur....

The Bolting and Torquing Activities program is a plant-specific program and is

not comparable to NUREG-1 801, Section XI.M1 8, "Bolting Integrity," which

stipulates the inspection requirements of ASME Code, Section Xl. These

requirements are included in the 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 Inservice Inspection

Program is not an applicable aging management program for these components.

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With respect to the inaccessible bolting aging management, the applicant stated the following:

When bolted closures are assembled, proper bolting material and appropriate

lubricants and sealants are selected in accordance with EPRI NP-5067, Good

Bolting Practices. Torque values are monitored when the bolted closure is

assembled. Maintenance personnel visually inspect components used in bolted

closures to assess their general condition during maintenance. Gaskets, gasket

seating surfaces, and fasteners are inspected for damage that would prevent

proper sealing. Therefore, the Bolting and Torquing Activities Program manages

aging effects for bolting, whether accessible or inaccessible. The Bolting and

Torquing Activities Program applies to bolting both inside and outside of

containment.

The GALL Report Bolting Integrity Program is a comprehensive program to manage bolted

closure integrity. It addresses the loss of material, cracking, and the loss of preload for all

bolted closures within the scope of license renewal, including safety related bolting, bolting for

nuclear steam supply system (NSSS) component supports, bolting for other pressure-retaining

components, and structural bolting. The CNP Bolting and Torquing Activities Program

addresses only the loss of preload for bolting subjected to elevated temperatures or significant

vibration, such as that due to diesel engine operation. This aging effect was conservatively

assumed to be applicable to bolting in systems with temperatures above 204 0C (400 .

0F), which

is below the 371 0C (700 'F) elevated temperature threshold for this aging effect accepted in

NUREG-1787, Safety Evaluation Report Related to the License Renewal of the Virgil C.

Summer Nuclear Station.

Other CNP programs address different aspects of GALL AMP XL.M18. For example, the CNP

Inservice Inspection Program includes the ASME Code, Section Xi, requirements for Class 1,

2, and 3 bolted closures. In addition, the Boric Acid Corrosion Prevention Program and System

Walkdown Program include periodic inspections of pressure-retaining components (including

the closure bolting) for signs of leakage that may be due to the loss of preload, cracking, or the

loss of material.

The staff finds the applicant's response reasonable and acceptable because the applicant has

clarified how the aging effects of cracking, SCC and the loss of preload would be managed in all

safety related bolting. Therefore, the staff's concerns described in RAI 3.2-5 are resolved.

RAI 3.2-12

The GALL Report recommends further evaluation of programs to manage the loss of material

due to pitting and crevice corrosion to verify the effectiveness of the Water Chemistry Control

Program. A one-time inspection of selected components at susceptible locations is an

acceptable method to determine whether an aging effect is occurring or is progressing so

slowly that the intended function will be maintained during the period of extended operation.

Tables 3.2.2-1, 3.2.2.2, and 3.2.2-3 of the LRA list various carbon steel components in a

treated water environment and stainless steel components in a borated water environment with

the aging effect of loss of material. The AMP for these components is the Water Chemistry

Control Program, but the tables listed above identify no one-time inspection program. However,

Appendix B to the LRA (page B-131) discusses a new plant-specific Chemistry One-Time

Inspection Program. The program description states that it is comparable to GALL AMP

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XL.M32 but is less broad in scope than the GALL program. In RAI 3.2-12, the staff asked the

applicant to clarify that the inspections and examinations performed within the scope of its new

Chemistry One-Time Inspection Program will verify the effectiveness of the Chemistry Control

Program in managing the aging effect of loss of material in the various carbon steel

components in a treated water environment and stainless steel components in a borated water

environment listed in LRA Tables 3.2.2-1, 3.2.2-2, and 3.2.2-3.

In its response, the applicant stated the following:

The Generic Aging Lessons Learned (GALL) report [Section XI.M2] identifies

those circumstances in which the water chemistry program is to be augmented to manage the effects of aging for license renewal. Accordingly, in certain cases

as identified in the GALL report, verification of the effectiveness of the chemistry control program is undertaken to ensure that significant degradation is not

occurring. As discussed in the GALL report for these specific cases, an

acceptable verification program is a one-time inspection of selected components at susceptible locations in the system. NUREG-1801 does not identify stainless

steel components in ESF systems as requiring augmentation of the water

chemistry program.

The applicant also stated the following:

...effectiveness of the chemistry control programs will be verified by the

Chemistry One-Time Inspection Program, as described in LRA Section B.1.41.

Inspections and examinations performed under this program will verify the

effectiveness of chemistry control programs in managing the aging effect of loss

of material for carbon steel in a treated water environment and stainless steel in

a borated water environment, as specified in NUREG-1 801.

The staff finds the applicant's response reasonable and acceptable because the applicant has

clarified how the Chemistry One-Time Inspection Program will verify the effectiveness of the

Chemistry Control Program. Therefore, the staff's concerns described in RAI 3.2-12 are

resolved.

3.2.2.3.1 Containment Spray System

Summary of Technical Information in the ApDlication

In Section 3.2.2.1.1 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs that manage the AERMs for the

Containment Spray System components:

* Boric Acid Corrosion Prevention Program * Heat Exchanger Monitoring Program

* Inservice Inspection - ASME Section Xl, Augmented Inspections Program * Service Water System Reliability Program * System Walkdown Program

* Water Chemistry Control Program

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In Table 3.2.2-1- 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 staff reviewed the AMR of the containment spray system component, material,

environment, and AERM combinations that the GALL Report does not address. These

combinations use notes F through J in LRA Table 3.2.2-1. The staff also reviewed those

combinations in Table 3.2.2-1, with notes A through E,'for which there are identified emerging'

issues. The staff verified 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 they adequately describe the programs.

Aging Effects

Table 3.2.2-1 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 an AMR

include bolting, eductor, heat exchanger (shell and tubes), heater housing, piping, manifolds,

orifices, spray nozzles, thermowells, nozzles, pump casing, tanks, tubing, and valves.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel components (bolting) in air (external) and outdoor air (external)

environments are subject to loss of material and loss of mechanical closure integrity.

* 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 also subject to loss of material-wear.

* Stainless steel components in treated, borated water (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.

* Stainless steel components in fresh raw water (external) and treated, borated water

(internal) environments are subject to fouling and also to loss of material-wear 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.

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* 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.

The staff reviewed the information in Section 3.2.2.1.1 and Table 3.2.2-1 in the LRA. During its

review, the staff determined that it needed additional information to complete its evaluation.

RAI 3.2-6 and 3.2-7

Table 3.2.2-1 of the LRA identifies a plant-specific Inservice Inspection Program for managing the aging effect caused by cracking and the loss of material in stainless steel thermowells and

valves in a sodium hydroxide environment. The table also identified a plant specific In-service

Inspection Program for managing the aging effect caused by cracking and the loss of material

in stainless steel tanks in an internal sodium hydroxide environment. The GALL Report does

not evaluate this combination of environment, material, and component. In RAIs 3.2-6 and 3.2-

7, the staff asked the applicant to discuss the plant-specific inspection methods, including the

frequency of inspections and acceptance criteria. The staff also asked the applicant to identify and justify any differences between the plant-specific program and the appropriate ASME

Code, Section Xl, requirements.

In its response, the applicant stated the following:

To manage cracking and loss of material of stainless steel thermowells and

valves in a sodium hydroxide environment, LRA Table 3.2.2-1 and LRA Section

B.1.18 identify an Augmented Inservice Inspection (ISI) Program that specifies volumetric inspections for portions of the containment spray system wetted by sodium hydroxide. Augmented inspections are specified for components that

are outside the jurisdiction of ASME Section Xl inspection requirements. Augmented inspections use the same non-destructive examination methods

used for ASME Section Xl inspections on Class 1, 2, or 3 components. The

inspections of the stainless steel thermowells and valves in the containment

spray system will use ultrasonic techniques, where feasible. The frequency of

inspections will be once every 10 years, consistent with ASME Section Xl, Subsection IWC, requirements for comparable Class 2 components. Acceptance criteria will be in accordance with the Class 2 acceptance criteria of

IWC-3000.

The staff finds the applicant's response to RAI 3.2-6 and RAI 3.2-7 technically sound and

acceptable because the applicant's inspection methods, acceptance criteria and frequency of

inspections conform to the ASME Section Xl requirements. In addition, the inspection frequency is also consistent with operating experience. Therefore, the staff's concerns

described in RAIs 3.2-6 and 3.2-7 are resolved.

RAI 3.2-8

Table 3.2.2-1 of the LRA does not identify any AERM for stainless steel tanks in a concrete

environment. In RAI 3.2-8, the staff asked the applicant to clarify whether periodic thickness

measurements taken specifically at weld locations and at the tank bottom ensure that the

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integrity of the tank is maintained. If so, the applicant should specify the frequency and method

of inspections.-

In its response, the applicant stated the following:

The stainless steel tank exposed to a concrete (external) environment, as

indicated in LRA Table 3.2.2-1, is the refueling water storage tank (TK-33), which

is depicted on license renewal drawings LRA-1 -5144 and LRA-2-5144 at location

B4. The tank base is in contact with the concrete pad. The concrete pads are

constructed in accordance with American Concrete Institute (ACI) specification

318-63, which results in high quality concrete free of contamination. Therefore,

loss of material is not an aging effect requiring management due to the inherent

corrosion resistance of stainless steel, alkalinity of concrete, and lack of

contamination. Since there are no aging effects requiring management for this

external stainless steel surface, periodic thickness measurements are not

required.

The staff finds the applicant's response reasonable and acceptable because the applicant has

provided a satisfactory explanation for not managing aging effects on the external surface of

stainless steel tanks exposed to a concrete environment. Therefore, the staff's concern

described in RAI 3.2-8 is resolved.

RAI 3.2-10

The GALL Report recommends a plant-specific AMP for the loss of material due to general,

pitting, and crevice corrosion and MIC in carbon steel components exposed to lubricating oil

that may be contaminated with water. Similar aging effects (except general corrosion) are

possible for copper alloy. The NRC staff considers a periodic inspection program appropriate

to manage this aging effect. In RAI 3.2-10, the staff asked the applicant to provide a periodic

inspection program in addition to the Oil Analysis Program for aging management of the loss of

material due to general (carbon steel), pitting, and crevice corrosion and MIC, or justify not

managing this aging effect, for the oil cooler shell in the ECCS (LRA Table 3.2.2-3) exposed to

an oil environment.

In its response, the applicant stated the following:

Loss of material is not an aging effect requiring management for surfaces

exposed to lubricating oil unless moisture or -contaminants are present. The Oil

Analysis Program monitors and controls abnormal levels of contaminants

(primarily water and particulates), thereby preserving an environment that is not

conducive to loss of material, cracking, or fouling. This is consistent with the

previously approved NRC Staff position documented in NUREG-1743, Safety

Evaluation Report Related to the License Renewal of Arkansas Nuclear One,

Unit 1, Section 3.3.1.4.7.

The response states that the loss of material is not an AERM for surfaces exposed to

lubricating oil unless moisture or contaminants are present. In GALL AMP XI.M32, the staff

states that where aging effects are not expected to occur but data are insufficient to completely

rule out their possibility, a one-time inspection is acceptable to confirm that aging effects are not

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occurring. An alternate acceptable program may include routine maintenance or a review of

repair records. The applicant stated that based on operating experience there is reasonable

assurance that the Oil Analysis Program will continue to manage the aging effects of

components exposed to lubricating oil; a review of the repair records supports this. The staff

finds the applicant's response reasonable and acceptable because the applicant has provided a

satisfactory explanation to the staff's concerns relating to the management of aging effects in

the oil coolers of the ECCS.

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 of the containment spray system and the staff's concern described in RAI 3.2-10 is

resolved.

Aging Management Programs.

After evaluating the applicant's identification of aging effects for each of the above component types, 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 programs.

Table 3.2.2-1 of the LRA identifies the following AMPs for managing the aging effects described

above for the containment spray system:

* Boric Acid Corrosion Prevention Program

* Heat Exchanger Monitoring Program

* Inservice Inspection-ASME Section Xl, Augmented Inspection Program * Service Water System Reliability Program

* System Walkdown Program

* Water Chemistry Control-Auxiliary Systems Water Chemistry Control Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.2.1, 3.0.3.3.5, 3.0.3.3.6, 3.0.3.2.11, 3.0.3.3.14, and 3.0.3.3.16 of this SER, respectively.

During its review, the staff determined that it needed additional information to complete its

evaluation.

In RAI 3.2-5, the staff 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. In addition, the staff asked the applicant to demonstrate that it will adequately manage the aging effects

associated with closure bolting with the Boric Acid Corrosion Prevention, Bolting and Torquing Activities, and System Walkdown Programs, or that it will manage them in a manner equivalent to that described in GALL AMP Xl.M1 8. Section 3.2.2.3 of this SER presents the staff's

discussion of this RAI and its resolution by the applicant.

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For carbon steel bolting exposed to air, the GALL Report does not address the loss of

mechanical closure integrity. In the LRA, for the loss of mechanical closure integrity in carbon`

steel bolting exposed to ambient air, the applicant proposed to use its Boric'Acid Corrosion

Prevention (CNP AMP B.1.4) and System Walkdown (CNP AMP B.1.38) Programs. The staff's

evaluation of the Boric Acid Corrosion Prevention Program and the System Walkdown Program

appears in Sections 3.0.3.2.1 and 3.0.3.3.14 of this SER, respectively.

The staff reviewed existing procedures, as well as the proposed enhancements related toevaluating the extent of degradation and criteria for initiating corrective actions. Because the

program will include detailed guidance for inspecting and evaluating the material condition of

SCs within the program's scope, and because the guidance will include specific parameters to

be monitored and criteria to be used for evaluating their condition, the staff finds that this

approach is an acceptable way to manage this aging effect when supplemented by an

approved Boric Acid Corrosion Prevention Program. The staff reviewed and accepted the Boric

Acid Corrosion Prevention Program as documented in Section 3.0.3.2.1 of this SER.:-

In the LRA, the applicant stated that no AMP is needed to address aging effects on stainless -

steel in an environment of air. The applicant did not identify an aging effect for stainless steel

components exposed to air (either internal or external). Component types identified include

bolting, eductor, heater housing (RWST electric heater), manifold (piping); orifice, piping, pump

casing, spray nozzle, tank, thermowell, tubing (instrument piping), and valves. The GALL

Report does not identify stainless steel as a material associated with some of these

components, and air is not a defined environment for the others.

Loss of material may be an applicable aging effect where stainless steel components are under

wet conditions and the components have crevice areas that may be exposed to fluids or have

areas where stagnant fluid may be present. The ambient environment for containment spray

components does not contain contaminants of sufficient concentration to cause aging effects

that require management. Based on industry experience for this combination of material and

environment, the staff finds that no AMP is required to manage the loss of material from

stainless steel components exposed to air at CNP.

In the LRA, the applicant stated that it will manage the loss of material from stainless steel

components in treated, borated water by using the Water Chemistry Control Program.

Component types identified include eductor, heater housing (RWST electric heater), heat

exchanger tubes, manifold (piping), orifice, piping, pump casing, tank, thermowell, tubing

(instrument piping), and valves. On the basis of industry experience that loss of material from

stainless steel components in chemically treated, borated water is not significant, the staff finds

that management of this aging effect using a water chemistry control program consistent with

the GALL Report is sufficient.

In the LRA, the applicant stated that it will manage fouling of stainless steel heater exchanger

tubes in treated water by using water chemistry control. The applicant cited a precedent that

implies that the Water Chemistry Control-Auxiliary Systems Water Chemistry Control Program

(CNP AMP B.1.40.3) applies. The staff's evaluation of this program appears in Section

3.0.3.3.16 of this SER. The GALL Report recommends managing loss of material using a '

program consistent with GALL AMP XI.M21 which more closely corresponds to the Water

Chemistry Control-Closed Cooling Water Chemistry Control Program (CNP AMP B.1.40.2).

The staff's evaluation of this program appears in Section 3.0.3.2.16 of this SER. Because

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these Water Chemistry Control Programs are consistent with the recommendations of the

GALL Report and each one allows management of fouling, the staff finds that the Water

Chemistry Control Programs will adequately manage fouling.

In the LRA, the applicant stated that it will manage fouling from stainless steel containment

spray heat exchanger tubes (internal) in treated, borated water by using the Water Chemistry Control Program. Because the Water Chemistry Control Program is consistent with the

recommendations of the GALL Report and allows management of fouling, the staff finds this

approach acceptable.

In the LRA, the applicant stated that stainless steel piping and valve component types in a

nitrogen gas environment are not subject to AERMs. Based on industry experience with this

combination of material and environment, the staff finds this 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 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 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).

3.2.2.3.2 Containment Isolation 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

AERMs. The applicant identified the following programs that manage the AERMs for the

Containment Isolation System components:

* Bolting and Torquing Activities Program

* Boric Acid Corrosion Prevention Program

* Containment Leakage Rate Testing Program

* System Walkdown Program

* Wall Thinning Monitoring Program

* Water Chemistry Control Program

In Table 3.2.2-2 of the LRA, the applicant provided a summary of AMRs for the Containment

Isolation System components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation

The staff reviewed the AMR of the containment isolation system component, material, environment, and AERM combinations that are not addressed in the GALL Report. These

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combinations use 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, with notes A through

E, for which emerging issues were identified. The staff verified that the 'applicant identified allapplicable 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 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 an AMR

include bolting, piping, and valves.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel components in air (external and internal), condensation (external and

internal), fresh raw water (internal), treated water (internal), and nitrogen (internal)

environments are subject to loss of material and loss of mechanical closure integrity. -

* Stainless steel components in environments of air (internal and external), condensation

(external), fresh raw water (internal), treated and borated water (internal and external),

and treated and borated water 132 0

C (270 OF) and above are subject to loss of

material, cracking, and loss of mechanical closure integrity.

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI 3.2-2

Table 3.2.2-2 of the LRA does not list any AERM for carbon steel piping with an internal

nitrogen environment. In RAI 3.2-2, the staff asked the applicant to discuss the potential for

moisture in the internal nitrogen environment and whether it periodically verifies that the

environment is moisture-free.

In its response, the applicant stated the following:

...the carbon steel piping with an internal nitrogen environment is shown on

license renewal drawings LRA-1 -5143A and LRA-2-5143A. The nitrogen inside

..this piping is supplied by the on-site nitrogen supply system shown on license

-renewal drawing LRA-12-5118B. The nitrogen gas inside the tanks that supply

these lines is provided by a vendor as 99.998% pure nitrogen with moisture less

than 5.0 parts per million. The nitrogen supply system does not contain

compressors that could introduce contaminants such as moisture. Since there is

minimal potential for moisture inside the carbon steel pipe associated with these

containment penetrations, sampling is not required.

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The staff finds the applicant's response reasonable and acceptable because the potential for

moisture in the internal nitrogen environment seems unlikely based on the information provided

by the applicant. Thus, the staff considers the issue related to this RAI resolved.

RAI 3.2-3

Table 3.2.2-2 of the LRA credits the Containment Leakage Rate Testing Program with

managing the loss of material in carbon steel piping in an air (internal) environment. This is a

plant-specific program, since the GALL Report does not evaluate a comparable environment for

carbon steel piping. In RAI 3.2-3, the staff asked the applicant to perform a one-time inspection

in addition to the Containment Leakage Rate Testing Program to identify and mitigate any

aging effects resulting from moisture in the internal air of the carbon steel piping.

In its response, the applicant identified the containment isolation system containment

penetrations with component types "piping" and "valve" listed in LRA Table 3.2.2-2 that are

constructed of carbon steel, contain air, and credit the Containment Leakage Rate Testing

Program with managing the loss of material.

The applicant stated the following:

...all identified penetrations are used during outages or are capped and are no

longer used. During normal operation, these penetrations contain only the air

that is trapped internal to the penetration. These penetrations are not exposed

to a continuous supply of air that could provide additional moisture and cause a

significant loss of material. The internal surfaces could experience minor

general corrosion but significant loss of material is not expected due to the

limited amount of moisture in the captured air within the penetration piping.

Containment leakage rate tests verify that leakage through components that

penetrate containment does not exceed allowable rates specified in the technical

specification or associated bases. In addition, periodic surveillance tests of the

components included as part of the Containment Leakage Rate Testing Program

are performed to verify that proper maintenance and repairs are made during the

service life of the containment. Negative trends and degraded conditions

identified by this program that could be indicative of loss of material would be

addressed by the Corrective Action Program. Therefore, the Containment

Leakage Rate Testing Program is adequate to manage the aging effect of loss

of material for these penetrations, and no one-time inspections are necessary.

The staff finds the applicant's response reasonable and satisfactory because the applicant has

provided justification to assure that the loss of material for these penetrations would be minimal

and the Containment Leakage Rate Testing Program has adequate provisions to identify any

degradation. Therefore, the staff considers RAI 3.2-3 issue resolved.

RAI 3.2-4

Table 3.2.2-2 of the LRA credits the Boric Acid Corrosion Prevention Program with managing

the loss of mechanical closure integrity for carbon steel bolts in an external air environment.

This AMP relies on the implementation of recommendations in NRC GL 88-05. Since this

program addresses components inside the containment, the staff issued RAI 3.2-4 asking the

I

I

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applicant to discuss the management of the loss of mechanical closure integrity of carbon steel

bolts outside the containment.

In its response, the applicant stated the following:

... the Boric Acid Corrosion Prevention Program manages loss of mechanical

closure integrity for carbon steel bolts on which borated reactor water may leak.

- It includes carbon steel bolts in an external air environment whether inside or

outside of containment.

Since the AMP scope goes beyond the GALL Report and covers other leaks besides those

from the RCPB, the staff's concern described in RAI 3.2-4 is resolved.

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 isolation 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 verified that the UFSAR Supplement adequately describes the

program.

Table 3.2.2-2 of the LRA identifies the following AMPs for managing the aging effects described

above for the containment isolation system:

* Boric Acid Corrosion Prevention Program

* Bolting and Torquing Activities Program

* System Walkdown Program

* Containment Leakage Rate Testing Program

* Water Chemistry Control-Chemistry One-Time Inspection Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.2.1, 3.0.3.3.2, 3.0.3.3.14,

3.0.3.1, and 3.0.3.3.17 of this SER, respectively. -

In the LRA, for the loss of mechanical closure integrity in carbon steel bolting exposed to

ambient air, the applicant proposed to use the Bolting and Torquing Activities (CNP AMP

B.1.2), Boric Acid Corrosion Prevention (CNP AMP B.1.4), and System Walkdown (CNP AMP

B.1.38) Programs. The staff's evaluation of these programs appears in Sections 3.0.3.3.2, -

3.0.3.2.1, and 3.0.3.3.14 of this SER, respectively.

The staff reviewed existing procedures, as well as the proposed enhancements related to

evaluating the extent of degradation and criteria for initiating corrective actions. Because the

program will include detailed guidance for inspecting and evaluating the material condition of

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SCs within the program scope, and because the guidance includes specific parameters to be

monitored and criteria to be used for evaluating their condition, the staff finds that this approach

is an acceptable way to manage this aging effect when supplemented by approved Bolting and

Torquing Activities and Boric Acid Corrosion Prevention Programs.

In the LRA, the applicant stated that no AMP is needed to address aging effects on stainless

steel in air (including condensation). This includes bolting, piping, and valve component types.

Loss of material may be an applicable aging effect where stainless steel components are under

wet conditions and the components have creviced areas that may be exposed to fluids or have

areas where stagnant fluid may be present. The environment for containment isolation

components does not contain contaminants of sufficient concentration to cause AERMs in

stainless steel. Based on industry experience for this combination of material and environment,

the staff finds that no program is required to manage the loss of material from stainless steel

components exposed to air at CNP.

The applicant in the LRA stated that it will manage the loss of material exposed to lubricating oil

by using CNP AMP B.1.23, "Oil Analysis," which is a plant-specific program. This applies to

brass, carbon steel, cast iron, copper alloy, and stainless steel. (Glass is also exposed to

lubricating oil, but there is no identified AERM for this material.)

The Oil Analysis Program analyzes for contaminants, anomalous particulates, and moisture. In

addition, beneficial additives are maintained in lubricating oils. The staff evaluation of this

program appears in Section 3.0.3.3.8 of this SER. On the basis of operating experience at

CNP, the staff concludes that this preventive program is effective in the management of aging

effects in this environment and finds the associated AMRs to be acceptable.

In the LRA, the applicant stated that it will manage cracking of stainless steel components in

treated, borated water greater than 132 0C (270 OF) by using water chemistry control. This is

proposed for piping and valve component types. The GALL Report suggests a plant-specific

program. While the Water Chemistry Control Program is expected to prevent and mitigate

aging effects, the staff finds that this may not be sufficient.

The staff asked the applicant to justify the absence of an inspection or monitoring program to

confirm the effectiveness of water chemistry control in managing this aging effect or identify the

program that will be used to do so. In the related RAI B.1.41-2, the staff asked the applicant to

provide a list of components, material types, environments, and aging effects that will be

inspected using its Water Chemistry Control-Chemistry One-Time Inspection Program (CNP

AMP B.1.41) and to justify that the components selected constitute an adequate sample size to

verify the effectiveness of the Water Chemistry Control Program for each aging effect to be

managed. Section 3.0.3.3.17 for this SER provides the staff's evaluation of the response to

RAI B.1.41-2.

The GALL Report does not address loss of material from components of stainless steel in

treated, borated water for the piping and valve component types. The applicant proposed to

manage this aging effect using the Water Chemistry Control Program. On the basis of industry

experience that loss of material from stainless steel components in chemically treated, borated

water is not significant, the staff finds that management of this aging effect using a Water

Chemistry Control Program that is consistent with the GALL Report is sufficient.

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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 containment

isolation 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 UFSAR Supplement program descriptions and concludes

that they adequately describe the AMPs credited with managing aging in these components, as

required by 10 CFR 54.21(d).

3.2.2.3.3 Emergency Core 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*

AERMs for the ECCS components. The applicant identified the following programs that

manage the AERMs for the ECCS components:

* Boric Acid Corrosion Prevention Program

* Heat Exchanger Monitoring Program

* Oil Analysis Program

* Preventive Maintenance Program

* System Testing Program

* System Walkdown Program

* Water Chemistry Control Program

In Table 3.2.2-3 of the LRA, the applicant provided a summary of AMRs for the ECCS

components and identified which AMRs it considered to be consistent with the GALL report.

Staff Evaluation

The staff reviewed the AMR of the ECCS component, material, environment, and AERM

combinations that are not addressed in the GALL Report. These combinations use notes F

through J in LRA Table 3.2.2-3, except for those for which there are past precedents: The staff

also reviewed those combinations in Table 3.2.2-3, with notes A through E, for which emerging

issues are identified. The staff verified that the applicant identified all applicable AERMs and

credited appropriate AMPs with managing the AERMs. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that they adequately describe the programs.

Aging Effects

Table 2.3.2-3 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 an AMR

include bolting, filter housing, flex hose, heat exchanger (shell and bonnet), heat exchanger

(tubes), heater housing, manifold (piping), orifices, piping, pump casing, strainer housing,

tanks, thermowell,-tubing, and valves.

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For these component types, the applicant identified the following materials, environments, and

AERMs:

* Cast iron components exposed to a treated water (internal) environment are subject to

the aging effect of loss of material. Cast iron components in air (external) environments

are subject to loss of material as well.

* Carbon steel components (bolting) in air (external) environments are subject to loss of

material and loss of mechanical closure integrity. Carbon steel exposed to a lubricating

oil (internal) environment is subject to loss of material.

* Stainless steel components in fresh raw water (internal) environments are subject to

loss of material. Stainless steel components in treated water (external), treated, borated

water (internal), and treated, borated water greater than 132 0C (270 OF) (internal)

environments are subject to fouling, cracking, and loss of material.

* In a treated, borated water (internal) environment, copper alloy components are subject

to fouling. Copper alloy components exposed to lubricating oil (external) are subject to

fouling. Copper alloys exposed to lubricating oil (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.

* Stainless steel components exposed to air (external) and nitrogen (internal)

environments experience no aging effects.

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI 3.2-1 1

Table 3.2.2-3 of the LRA states that the Water Chemistry Control Program will manage loss of

material for the copper alloy oil cooler tubes for the pump in a cooling water environment. For

this material type and environment, the staff considers selective leaching to be an AERM. In

RAI 3.2-11, the staff asked the applicant whether it considered selective leaching to be an

aging mechanism for the tubes. If so, the applicant should describe the types of inspections it

will use to detect selective leaching in the tubes.

In its response, the applicant stated the following:

...the copper alloy tubes identified in LRA Table 3.2.2-3 are part of small shell

and tube heat exchangers that provide cooling for the oil lubricating the safety

injection (SI) pump bearings and centrifugal charging pump (CCP) bearings and

gear assemblies. Component cooling water is supplied through the heat

exchanger tubes. The component cooling water system is a closed-loop system treated with corrosion inhibitors....

Selective leaching was identified in the aging management review as one of the

mechanisms that could result in the aging effect of loss of material for copper

alloy internal surfaces. The Closed Cooling Water Chemistry Control Program

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includes preventive measures that manage loss of material, including that due to

selective leaching, where applicable. The Chemistry One-Time Inspection

Program will verify the effectiveness of the chemistry programs to manage the

effects of aging such that components will perform their intended functions for

the period of extended operation. In addition, these heat exchangers will be -

included in the Heat Exchanger Monitoring Program, which will inspect the heat

exchangers for degradation using nondestructive examinations, such as eddy

current inspections or visual inspections or, if appropriate, the heat exchangers

will be replaced. This combination of preventive measures and inspections are

adequate to provide reasonable assurance that all aging effects, including

selective leaching, will be managed and that the components will perform their

pressure boundary intended function during the period of extended operation.

The Heat Exchanger Monitoring Program will include activities to manage loss of

material due to selective leaching. Brinell Hardness testing will be performed on

selected heat exchanger tubes that are susceptible to selective leaching, when

feasible. However, Brinell Hardness testing may not be feasible for some

components due to form and configuration (e.g., heat exchanger tubes). In such

cases, examinations other than Brinell Hardness testing may be used to identify

the presence of selective leaching of material. Other mechanical means, such

as scraping or chipping, will provide an effective method for identifying selective

leaching.

The staff finds the applicant's response reasonable and acceptable because the applicant has

identified satisfactory methods for detecting selective leaching. Therefore, the staff's concern

described in RAI 3.2-11 is resolved.

RAI 3.2-13

Table 3.2.2-3 of the LRA lists the loss of material and erosion as AERMs for the flow

orifices/elements, but it does not list cracking. The staff considers cracking a possible AERM

for flow orifices/elements. In RAI 3.2-13, the staff asked the applicant to describe the flow

orifices/elements, their location in the system, and why it does not consider cracking to be an

AERM.

In its response, the applicant identified the various restricting orifices and flow-metering orifices

in LRA Table 3.2.2-3. These stainless steel components are exposed to water with a

temperature below the 60 0C (140 0F) cracking threshold for intergranular attack or SCC.

These components are not subject to cracking from thermal fatigue because they are not

exposed to the elevated temperatures that are required for this aging effect. Therefore,

cracking is not an AERM for these components. The staff finds the applicant's response

reasonable and acceptable because the applicant has identified the various flow orifices and

their locations in the system and provided adequate assurance that cracking is not likely to

occur. Therefore, the staff's concern described in RAI 3.2-13 is resolved.

RAI 3.2-14

Table 3.2.2-3 of the LRA states that a plant-specific Preventive Maintenance Program manages

cracking in the pump casing with an internal stainless steel cladding, in a borated water

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environment. The applicant stated that this cracking is not SCC but is a component-specific

cracking resulting from stress concentration. In RAI 3.2-14, the staff asked the applicant to

provide information about (a) the inspection frequency of these charging pumps including the

bases of the frequency, (b) the operating history of the pumps, and (c) whether it has

performed an evaluation of fatigue resulting from pressure cycling to rule out fatigue-cracking

as a factor. If so, the applicant should provide that evaluation.

In its response, the applicant stated the following:

(a) The current CCP inspection frequency is once every four fuel cycles.

The inspection frequency was based upon the stress analysis and the

corrosion rates of carbon steel subjected to boric acid, as described in

NRC Information Notice (IN) 80-38, "Cracking in Charging Pump Casing

Cladding," and based upon plant-specific inspection results, which are

summarized in the following table:

Date

March 1992

July 1992

August 1995

April 1996

October 1999

Pump Results

2-PP-50E No indications that required repairs were found

1 -PP-50E

1 -PP-50W

2-PP-50W

2-PP-50E

Identified and repaired crack indications (1 inch

to 81⁄2/2 inches in length) on discharge side.

Identified and repaired crack indications on

pump inboard and outboard ends.

No indications that required repairs were found

Identified and repaired a %-inch long linear

indication in the pump inlet nozzle.

August 2000

January 2002

1-PP-50E Identified and repaired linear indications in the

pump inboard and outboard nozzles.

2-PP-50W Identified and repaired two 'A-inch long flaws in

the pump inlet nozzle.

May 2002

May 2003

1-PP-50W

2-PP-50W

No indications that required repairs were found

Identified and repaired four indications that

reached the carbon steel substrate under the

cladding at the pump inlet nozzle.

(b) A review of condition reports and inservice testing results since 1999 did

not reveal any significant events related to operation of the CCPs.

Significant events related to operation of the CCPs prior to 1999 are

summarized below:

Licensee Event Report (LER) 50-315/77-18, dated May 3, 1977, reported that

the Unit 1 west CCP failed due to a broken shaft. The rotating element was

replaced and the pump returned to service. The failure was described as a clean

break occurring under the eleventh stage impeller with indications that fatigue

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was the failure mechanism. The vendor traced the failure to a bad heat used in

the manufacture of the shafts.

LER 50-315/77-20, dated June 1, 1977, reported that the Unit 1 east CCP shaft :

broke between the third and fourth stage impellers. The break appeared to be a,

fatigue failure. The vendor traced the failure to a bad heat used in the

manufacture of the shafts.

LER 82-032/03L-0, dated May 3, 1982, reported that the Unit 2 east CCP was

removed from service during the previous month to replace the mechanical seal.

LER 82-046/03L-0, dated July 6, 1982, reported that the Unit 1 east CCP was

declared inoperable as a result of excessive vibration. The pump rotating

assembly was replaced. During repairs, pitting erosion/corrosion through the

stainless steel cladding and into the carbon steel pump case was identified at the

suction and discharge nozzles. The affected areas were ground out and

repaired by welding.

LER 83-090/03L-0, dated September 20, 1983, reported that during an ECCS

flow balance, the Unit 1 west CCP minimum flow was below the minimum

-allowable rate.. NRC inspection report 50-31583-14, dated October 5, 1983,

documented that the pump rotating element was replaced.

LER 86-012-01, dated December 4, 1986, reported that, with the Unit 2 west

CCP operating, attempts to balance system flow failed due to degraded

performance of the pump. The pump rotating element was replaced.

LER 93-006-00, dated August 9, 1993, reported that the Unit 2 west CCP was

declared inoperable due to high vibration. Upon disassembly of the rotor

assembly, the pump shaft was found to be cracked. The pump rotor assembly

was replaced with a rebuilt assembly.

(c) Fatigue evaluations for pressure cycling have not been performed, since

cladding failure of the charging pump cladding is a defect caused by

stress concentrations, as discussed in NRC IN 80-38, and is not a fatigue

issue.

Based on a review of the operating history of the pump, the staff finds that the cracking in the

pump is most likely not the result of SCC but is a component-specific cracking resulting from

stress concentration, as the applicant contended. The staff therefore finds the applicant's

response acceptable, and the staff's concerns described in RAI 3.2-14 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 RAI, the staff finds.that the aging effects of

the above ECCS component types that are not addressed in the GALL Report and the specific

component types that are within the scope of review are consistent with industry experience for

these combinations of materials and environments. The staff did not identify any omissions of

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 ECCS.

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Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above component

types, 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.

Table 3.2.2-3 of the LRA identifies the following AMPs for managing the aging effects described

above for the SFP system component types that are within the scope of review:

* Boric Acid Corrosion Prevention Program

* System Walkdown Program

* Water Chemistry Control-Chemistry One-Time Inspection Program

* Oil Analysis Program

* Preventive Maintenance Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.2.1, 3.0.3.3.14, 3.0.3.3.17,

3.0.3.3.8 and 3.0.3.3.10 of this SER, respectively.

In the LRA, the applicant stated that it will manage loss of mechanical closure integrity in

high-temperature or high-pressure systems for carbon steel bolting exposed to ambient air by

using its Bolting and Torquing Activities (CNP AMP 8.1.2), Boric Acid Corrosion Prevention

(CNP AMP B.1 .4), and System Walkdown (CNP AMP B.1 .38) Programs. The staff's evaluation

of these programs appears in Sections 3.0.3.3.2, 3.0.3.2.1, and 3.0.3.3.14 of this SER,

respectively.

The staff reviewed existing procedures, as well as the proposed enhancements related to

evaluating the extent of degradation and criteria for initiating corrective actions. Because the

program will include detailed guidance for inspecting and evaluating the material condition of

SCs within the program scope, and because the guidance includes specific parameters to be

monitored and criteria to be used for evaluating their condition, the staff finds that this approach

is an acceptable way to manage this aging effect when supplemented by approved Bolting and

Torquing Activities and Boric Acid Corrosion Prevention Programs.

For stainless steel exposed to ambient air, the applicant identified no AERMs. The component

types affected are bolting, flex hose, heater housing, orifice, manifold, piping, pump casing

strainer housing, tank, thermowell, tubing, and valves. No aging effects are identified for piping

and valves exposed to nitrogen (gas). Because there are no identified AERMs, and because

this is consistent with industry experience, the staff finds the absence of an AMP for stainless

steel components exposed to ambient air and nitrogen to be acceptable.

In the LRA, the applicant stated that it will use its Oil Analysis Program (CNP AMP 8. 1.23) to

manage the loss of material from carbon steel filter housing, heat exchanger shell, piping pump'

casing, and tank; copper alloy heat exchanger shell and tubes, piping, and valves; stainless

steel piping; and cast iron pump casing component types. Section 3.0.3.3.8'of this SER

documents the staff evaluation of this program. Because the Oil Analysis Program maintains

oil systems free of contaminants (primarily water and particles), the staff finds that this program

adequately manages the loss of material for components'expos'ed to lubricating oil.

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In the LRA, the applicant stated that the GALL Report does not address loss of material from

components of stainless steel in treated, borated water for the flex hose, heat exchanger tubes,

heater housing, manifold, orifice, piping, pump casing, strainer housing, tank, thermowell,

tubing, or valve component types, hor for pump casing and tanks clad with stainless steel. The

applicant proposed to manage this aging effect using the Water Chemistry Control Program.

On the basis of industry experience showing that loss of material from stainless steel

components in chemically treated, borated water is not significant, the staff finds that

management of this aging effect using a water chemistry control program consistent with the

GALL Report is sufficient.

The applicant in the LRA did not identify any AERMs for copper alloy heat exchanger, piping,

and valve component types exposed to ambient air. Based on industry experience for this

combination of material and environment, the staff finds this to be acceptable.

In the LRA, the applicant stated that it will manage cracking of stainless steel components in

treated, borated water greater than 132 0C (270 OF) by using water chemistry control. This is

proposed for. heat exchanger tubes, manifold, piping, pump casing, strainer housing,

thermowell, tubing, and valve component types. The GALL Report suggests a plant-specific

AMP. While the Water Chemistry Control Program is expected to prevent and mitigate aging

effects, the staff finds that its use alone may not be sufficient.

The staff asked the applicant to justify the absence of an inspection or monitoring program to

confirm the effectiveness of water chemistry control in managing this aging effect or to identify

the program that it will use to do so. In the related RAI 8.1.41-2, the staff asked the applicant

to provide a list of components, material types, environments, and aging effects that it will -; -

inspect using its Water Chemistry Control-Chemistry One-time Inspection Program (CNP AMP

B.1.41) and to justify that the components selected constitute an adequate sample size to verify

the effectiveness of the Water Chemistry Control Program for each aging effect to be managed.

Section 3.0.3.3.17 for this SER provides the staff's evaluation of the response to RAI B.1.41-2.

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 ECCS

components that are not addressed by the GALL Report and those specific component types

that are within the scope of 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 they adequately describe the AMPs credited with managing aging in these components, as

required by 10 CFR 54.21 (d).

3.2.2.3.4 Containment Equalization/Hydrogen Skimmer System

Summary of Technical Information in the ADplication

In Section 3.2.2.1.4 of the LRA, the applicant identified the materials, environments, and

AERMs for the Containment Equalization / Hydrogen Skimmer (CEQ) System components.

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I

The applicant identified the following programs that manage the AERMs for the CEQ system

components:

* Boric Acid Corrosion Prevention Program

* Heat Exchanger Monitoring Program

* System Walkdown Program

* Water Chemistry Control Program

In Table 3.2.2-4 of the LRA, the applicant provided a summary of AMRs for the Containment

Equalization / Hydrogen Skimmer components and identified which AMRs it considered to be

consistent with the GALL report.

Staff Evaluation

The staff reviewed the AMR of the CEQ system component, material, environment, and AERM

combinations that are not addressed in the GALL Report. These combinations use notes F

through J in LRA Table 3.2.2-4, except for those for which there are past precedents. The staff

also reviewed those combinations in Table 3.2.2-4, with notes A through E, for which emerging

issues are identified. The staff verified 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 they adequately describe the programs.

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 an AMR

include bolting, damper housing, piping, valves, ductwork, fan housing, and heat exchanger.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel components in air (external) environments are subject to loss of material

and loss of mechanical closure integrity.

* Stainless steel components in air (external and internal) and condensation (internal)

environments experience no aging effects.

* Copper alloy pressure boundary components exposed to external air are subject to loss

of material-wear.

* Copper alloys exposed internally to treated water are subject to erosion and loss of

material.

During its review, the staff determined that it needed additional information to complete its

evaluation.

The applicant determined that none of the piping components in the ESF system will exceed

7000 cycles during the period of extended operation. In RAI 3.2-1, the staff asked the applicant

to provide the highest estimated number of thermal cycles and the basis for identification for

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each component type in Tables 3.2.2-1 through 3.2.2-4 of the LRA for which the TLAA-Metal

Fatigue Program is the designated AMP. For those components for which the GALL Report

does not specify material or aging effect (designated as notes F and I respectively), the staff

asked the applicant to clarify whether it performs the thermal cycle evaluation in accordance

with SRP-LR, Section 4.3.1.1.2. If so, the applicant should state whether its TLAA program is

consistent with the GALL Report, and if not, it should explain any differences. The staff also

asked the applicant to address how its estimates account for unanticipated transients and

thermal stratification, where applicable.

In its response, the applicant stated the following:

The evaluation of cracking by fatigue was identified as a time-limited aging

--analysis (TLAA) for selected mechanical components in the containment

isolation system (LRA Table 3.2.2-2) and the emergency core cooling system

(ECCS) (LRA Table 3.2.2-3). Evaluation of cracking by fatigue was not identified

as a TLAA for components in the containment spray system (LRA Table 3.2.2-1)

or the containment equalization/hydrogen skimmer system (LRA Table 3.2.2-4).

Section 3.2.2.3 of this SER discusses the applicant's response to RAI 3.2-1 in further detail.

Aging Management Programs

Table 3.2.2-4 of the LRA identifies the following AMPs for managing the aging effects described

above for the hydrogen control system:

* Boric Acid Corrosion Prevention Program

* Heat Exchanger Monitoring Program

* Water Chemistry Control-Auxiliary Systems Water Chemistry Control Program

* System Walkdown Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.2.1, 3.0.3.3.5, 3.0.3.3.16,

and 3.0.3.3.14 of this SER, respectively.

In the LRA, the applicant stated that it will manage the loss of mechanical closure integrity in

carbon steel bolting exposed to ambient air, by using its Boric Acid Corrosion Prevention (CNP

AMP B.1.4) and System Walkdown.(CNP AMP B.1.38) Programs. The staff's evaluation of

these programs appears in Section 3.0.3.2.1 and 3.0.3.3.14 of this SER, respectively.

The staff reviewed existing procedures, as well as the proposed enhancements related to

evaluating the extent of degradation and criteria for initiating corrective actions. Because the

program will include detailed guidance for inspecting and evaluating the material condition of

SCs within the program scope, and because the guidance includes specific parameters to be.

monitored and criteria to be used for evaluating their condition, the staff finds that this approach

is an acceptable way to manage this aging effect when supplemented by an approved Boric

Acid Corrosion Prevention Program.

In the LRA, the applicant identified no AERMs for stainless steel bolting or copper-alloy heat

exchanger component types exposed to ambient air. Because there are no identified AERMs,

and because this is consistent with industry experience, the staff finds the absence of an AMP

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for stainless steel components exposed to ambient air and nitrogen to be acceptable. The staff

reviewed all other AMRs assigned in Tables 3.2.2-1 through 3.2.2-4 of the LRA and finds them

to be 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 CEO 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 UFSAR Supplement program descriptions and concludes

that they adequately describe the AMPs credited with managing aging in these components, as

required by 10 CFR 54.21(d).

3.2.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the ESF system components and component

groups that are within the scope of license renewal and subject to an AMR so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

auxiliary systems components and component groups associated with the following systems:

* spent fuel pool system

* essential service water system

* component cooling water system

* compressed air systems

* chemical and volume control system

* heating, ventilation, and air conditioning systems

* fire protection system

* emergency diesel generator system

* security diesel system

* postaccident containment hydrogen monitoring system

* miscellaneous systems in scope for 10 CFR 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, AERMs, and AMPs associated with each

system.

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In Table 3.3.1, "Summary of Aging Management Programs for the Auxiliary Systems Evaluated

in Chapter VII of NUREG-1i801," 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 Section 3.3 of the LRA to understand the applicant's review process and to

determine whether the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the auxiliary systems components that are within

the scope of license renewal and subject to an AMR 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 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 verify that

the material presented in the LRA is applicable and that the applicant identified the appropriate

GALL AMRs. Section 3.3.2.1 of this SER summarizes the staff's audit findings.

The staff also audited those AMRs that are consistent with the GALL Report and for which

further evaluation is recommended. The staff verified that the applicant's additional evaluations

are consistent with the acceptance criteria in Section 3.3.3.2 of the SRP-LR. Section 3.3.2.2 of

this 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 the applicant identified all plausible

aging effects and listed the aging effects 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

auxiliary systems and associated components.

Table 3.3-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.3 that are addressed in the GALL Report.

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report

Component Aging Effect/ AMP in GALL Report -,AMP in LRA Staff Evaluation

Group" Mechanism -

Components Loss of material due Water Chemistry and Not applicable Consistent with

in spent fuel to general, pitting, and One-Time Inspection GALL. which

pool cooling crevice corrosion recommends

and cleanup further evaluation

(Item Number (See Section

3.3.1-1) 3.3.2.2.1)

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Component Aging EffectV . 7 AMP in GALL Report - AMP in LRA: Staff Evaluation

Group. Mechanism-.:-

Linings in Hardening, cracking, Plant specific Not applicable for Consistent with

spent fuel and loss of strength spent fuel cooling GALL, which

cooling and due to elastomer systems. Preventive recommends

cleanup degradation; loss of Maintenance Program further evaluation

system; seals material due to wear (B.1.25); Service (See Section

and collars in Water System 3.3.2.2.2)

ventilation Reliability Program

systems (B.1.29); Fire

(Item Number Protection Program

3.3.1-2) (B.1.11)

Components Cumulative fatigue TLAA, evaluated in TLAA Consistent with

in load damage accordance with GALL, which

handling, 10 CFR 52.21c) recommends

chemical and further evaluation

volume (See Section

control 3.3.2.2.3)

system

(PWR), and

reactor water

cleanup and

shutdown

cooling

systems

(older BWR)

(Item Number

3.3.1-3)

Heat * Crack initiation and Plant specific Preventive Consistent with

exchangers growth due to SCC or Maintenance Program GALL, which

in reactor cracking (B.1.25) recommends

water further evaluation

cleanup (See Section

system 3.3.2.2.4)

(BWR); highpressure

pumps in

chemical and

volume

control

system

(PWR) (Item

Number

3.3.1-4)

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Component :--'-Aging Effect!-;- . AMP in GALL Report AMP In LRA Staff Evaluation

Group - Mechanism - - *- - , - ''*- -;

Components Loss of material due Plant specific System Walkdown Consistent with

in ventilation to general, pitting, and Program (B.1.38); GALL, which

systems, crevice corrosion, and System Testing - recommends

diesel fuel oil MIC Program (B.1.37); further evaluation

system, and Service Water System (See Section

EDG Reliability Program 3.3.2.2.5)

systems; (B.11.29); Preventive

external Maintenance Program

surfaces of (B.1.25); Fire

carbon steel Protection Program

components (B.1.1 1)

(Item Number

3.3.1-5)

Components Loss of material due One-Time Inspection Boric Acid Corrosion Consistent with

in RCP oil to galvanic, general, Prevention Program GALL, which

collection pitting, and crevice (B.1.4); Preventive recommends

system of fire corrosion Maintenance Program further evaluation

protection (B..1.25) (See Section

(Item Number 3.3.2.2.6)

3.3.1-6)

Diesel fuel oil Loss of material due Fuel Oil Chemistry Diesel Fuel Monitoring Consistent with

tanks in to general, pitting, and and One-Time Program (B.1.10) GALL, which

diesel fuel oil crevice corrosion, Inspection recommends

system and MIC, and biofouling further evaluation

EDG system (See Section'

(Item Number 3.3.2.2.7)

3.3.1-7)

Heat Crack initiation and Water Chemistry and Water Chemistry Consistent with

exchangers growth due to SCC plant-specific Control Program GALL, which

in chemical and cyclic loading verification program (B.1.40); Heat recommends

and volume Exchanger Monitoring further evaluation

control Program (B.1.13); (See Section

system (Item Water Chemistry 3.3.2.2.9)

Number Control-Chemistry

3.3.1-9) One-Time Inspection

Program (B.1.41)

Neutron- Reduction of neutron- Plant specific Boral Surveillance Consistent with

absorbing absorbing capacity Program (B.1.3); GALL, which

sheets in and loss of material Water Chemistry recommends

spent fuel due to general Control Program further evaluation

storage racks corrosion (boral, boron (B.1.40) (See Section

(Item Number steel) 3 .3.2.2.10)

3.3.1-10) -

New fuel rack Loss of material due Structures Monitoring Not applicable Consistent with

assembly to general, pitting, and GALL, which

(Item Number crevice corrosion recommends no

3.3.1-11) further evaluation

(See Section

3.3.2.1)

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Component - Aging Effectl/,, AMP in GALL Report AMP in LRA ^ Staff Evaluation

Group Mechanismn - - - :- -- .-

Neutron- Reduction of neutron- Boraflex Monitoring Not applicable Consistent with

absorbing absorbing capacity GALL, which

sheets in due to Boraflex recommends no

spent fuel degradation further evaluation

racks (Item (See Section

Number 3.3.2.1)

3.3.1-12)

Spent fuel Crack initiation and Water Chemistry Not applicable Consistent with

storage racks growth due to SCC GALL, which

and valves in recommends no

spent fuel further evaluation

pool cooling (See Section

and cleanup 3.3.2.1)

(Item Number

3.3.1-13)

Closure Loss of material due Boric Acid Corrosion Boric Acid Corrosion Consistent with

bolting and to boric acid corrosion Prevention Program GALL, which

external (B.1.4) recommends no

surfaces of further evaluation

carbon steel (See Section

and low-alloy 3.3.2.1)

steel

components

(Item Number

3.3.1-14)

Components Loss of material due Closed-Cycle Cooling Water Chemistry Consistent with

in or serviced to general, pitting, and Water System Control-Closed GALL, which

by closed- crevice corrosion, and Cooling Water recommends no

cycle cooling MIC Chemistry Control further evaluation

water system Program (B.1.40.2) (See Section

(Item Number 3.3.2.1)

3.3.1-15)

Cranes Loss of material due Overhead Heavy Load Structures Consistent with

including to general corrosion and Light Load Monitoring-Crane GALL, which

bridge and and wear Handling Systems Inspection Program recommends no

trolleys and (B.1.33) further evaluation

rail system in (See Section

load handling 3.3.2.1)

system (Item

Number

3.3.1-16)

Components Loss of material due Open-Cycle Cooling Service Water System Consistent with

in or serviced to general, pitting, Water System Reliability Program GALL, which

by open- crevice, and galvanic (B.1.29); System recommends no

cycle cooling corrosion, MIC, and Testing Program further evaluation

water boifouling; buildup of (B.1.37); Water (See Section

systems deposit due to Chemistry Control 3.3.2.1)

(Item Number biofouling Program (B.1.40)

3.3.1-17)

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,Component -Aging Effect! ' AMP In GALL Report --'-,AMP In LRA -.Staff Evaluation'

Group - Mechanism ,- - -

Buried piping Loss of material due Buried Piping and Buried Piping Consistent with

and fittings to general, pitting, and Tank Surveillance Inspection Program GALL, which

(Item Number* crevice corrosion, and (B.1.6); System recommends no

3.3.1 -18) MIC or Testing Program further evaluation

(B.1.37) (See Section

Buried Piping and 3.3.2.1)

Tanks Inspection . Consistent with

GALL, which

recommends'

further evaluation

(See Section

3.3.2.2.11)

Components Loss of material due Compressed Air Containment Leakage Consistent with

in to general and pitting Monitoring Rate Testing Program GALL, which :'-

compressed corrosion (B.1.8) recommends no

air system further evaluation

(Item Number (See Section

3.3.1-19) 3.3.2.1)

Components Loss of material due Fire Protection Fire Protection - Consistent with

(doors and to wear; hardening Program (B.1.11) GALL, which

barrier - - and shrinkage due to recommends no'

penetration weathering further evaluation

seals) and -- - (See Section- -

concrete -3.3.2.1)

structures in

fire protection

(Item Number

3.3.1-20)

Components Loss of material due Fire Water System Not applicable Consistent with

in water- to general, pitting, GALL, which

based fire - crevice, and galvanic recommends no

protection corrosion, MIC, and further evaluation

(Item Number biofouling (See Section

3.3.1-21) 3.3.2.1)

Components Loss of material due - Fire Protection and Diesel Fuel Monitoring Consistent with

in diesel fire to galvanic, general, Fuel Oil Chemistry Program (B.1.10) - GALL, which -

system (Item pitting, and crevice recommends no

Number- corrosion further evaluation

3.3.1-22) -(See Section . : - 3.3.2.1).

Tanks in Loss of material due Aboveground Carbon System Walkdown Consistent with

diesel fuel oil to general, pitting, and Steel Tanks Program (B.1.38) GALL, which

system (Item crevice corrosion recommends no

Number further evaluation

3.3.1-23) (See Section

3.3.2.1)

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Component -Aging- Effect/- .AMP in GALL Report AMP In LRA; .-: Staff Evaluations

Group,-- 2 Mechanism - *-:--. <, - -.

Closure Loss of material due Bolting Integrity Bolting and Torquing Consistent with

bolting (Item to general corrosion; Activities Program GALL, which

Number crack initiation and (B.1.2); System recommends no

3.3.1-24) growth due to cyclic Walkdown Program further evaluation

loading and SCC (B.1.38) (See Section

3.3.2.1)

Components Loss of material due Selective Leaching of Service Water System Consistent with

(aluminum, to selective leaching Materials Reliability Program GALL, which

bronze, cast (B.1.29); Water recommends no

iron, cast Chemistry Control further evaluation

steel) in Program (B.1.40) (See Section

open-cycle 3.3.2.1)

and closedcycle cooling

water

systems, and

ultimate heat

sink (Item

Number

3.3.1-29)

Fire barriers, Concrete cracking and Fire Protection and Not applicable Consistent with

walls, spalling due to freeze- Structures Monitoring GALL, which

ceilings, and thaw, aggressive recommends no

floors in fire chemical attack, and further evaluation

protection reaction with (See Section

(Item Number aggregates; loss of 3.3.2.1) 3.3.1-30) material due to

corrosion of

embedded steel

The staff's review of the auxiliary systems and associated components followed one of several

approaches. One approach, documented in Section 3.3.2.1 of this SER, involves the staff's

review of the AMR results for components in the auxiliary systems 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 review of the AMR results for

components in the auxiliary systems that the applicant indicated are consistent with the GALL

Report and for which further evaluation is recommended. A third approach, documented in

Section 3.3.2.3 of this SER, involves the staff's review of the AMR results for components in the

auxiliary systems that the applicant indicated are not consistent with the GALL Report or that

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 aging effects of the auxiliary systems

components.

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3.3.2.1 Aging Management Evaluations That Are Consistent with the GALL Report, for Which

No Further Evaluation Is Required

Summary of Technical Information in the Arnlication

In Section 3.3.2.1 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

auxiliary systems components:

* Boral Surveillance Program

* Water Chemistry Control Program

* Service Water System Reliability Program

* System Walkdown Program

* Heat Exchanger Monitoring Program

* . Oil Analysis Program

* Containment Leakage Rate Testing Program

* Instrument Air Quality Program

* Preventive Maintenance Program

* Boric Acid Corrosion Prevention Program

* -System Testing Program

* Bolting and Torquing Activities Program

* Diesel Fuel Monitoring Program

* Fire Protection Program

* Buried Piping Inspection 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 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 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 the alignment of the

information in the tables with the information in the GALL Report. The staff audited those - -

AMRs with notes A through E, where applicable, which indicate that the AMR is consistent with

the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

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Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that 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 still consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report. However, the applicant

identified a different component in the GALL Report that has the same material, environment,

aging effect, and AMP as the component 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 is applicable 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 still consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff determined whether the AMR line item of

the different component is applicable to the component under review. The staff verified 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 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 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 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 verify that the material presented in the LRA is applicable

and that the applicant identified the appropriate GALL AMRs. The following sections discuss

the staff evaluation.

3.3.2.1.1 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

In the LRA, the applicant stated that it will manage loss of material and cracking for stainless

steel, carbon steel, and copper alloy exposed to treated water in the CCW system with its

Water Chemistry Control-Closed Cooling Water Chemistry Control Program (CNP AMP

B.1.40.2). The applicant stated that this program is consistent with GALL AMP XI.M21, with

exceptions. Section 3.0.3.2.16 of this SER documents the staff evaluation of this program.

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The GALL Report recommends, in addition to water chemistry control, performance monitoring

and functional testing of components managed with this program. The staff asked the applicant

to provide justification or a commitment to apply an appropriate testing and/or monitoring

program to manage these aging effects. In related RAI B.1.41-2, the staff asked the applicant

to provide a list of components, material types, environments, and aging effects that will be

inspected using the Water Chemistry Control-Chemistry One-Time Inspection Program (CNP

AMP B.1.41) and to justify that the components selected are an adequate sample size to verify

the effectiveness of the Water Chemistry Control Program for each aging effect to be managed

(see Section 3.0.3.3.17 of this SER for the staff's evaluation of the responses to this RAI).

In the LRA, the applicant stated that it will manage the loss of material from copper alloy

components exposed to raw water in the HVAC systems by using its Service Water System

Reliability (CNP AMP B.1.2). Section 3.0.3.2.11 of this SER documents the staff's evaluation of

this program. The GALL Report suggests the use of programs consistent with GALL AMP

XI.M20 and GALL AMP XI.M33. The latter program recommends both visual inspection and

hardness testing to monitor this aging effect. The applicant has not identified how the Service

Water System Reliability Program will adequately monitor this aging effect.

By letter dated May 6, 2004, the staff asked the applicant, in RAI 3.3.2-2, to provide justification

for excluding a hardness measurement from the Service W~ater System Reliability Program to

detect selective leaching (see Section 3.3.2.3.2 for the staff's evaluation of the responses to

this RAI).

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 applicant credited the Service Water System Reliability Program with managing loss of

material in stainless steel, elastomer, carbon steel, copper alloy, and cast iron exposed to fresh,

raw water (internal) in the ESW system. The Service Water System Reliability Program takes

exception to the GALL AMP requirements concerning the lining or coating of components. The

applicant stated that components are lined or coated only when necessary to protect underlying

metal surfaces. -The staff found this acceptable. However, Section B.1.29 of the LRA indicates

loss of material only for the enhancement of the program for the 8-inch expansion joints in the

ESW supply lines to the EDG heat exchangers, and not for any other component or material.

On the basis of its audit and review, the staff determined that for all other AMRs not requiring

further evaluation, as identified in LRA Table 3.3.1 (Table 1), the applicant's references to the

GALL Report are acceptable and no further staff review is required.

The staff 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, as required byl 0 CFR 54.21 (a)(3). -

Conclusion

The staff has verified the applicant's claim of consistency with the GALL Report. The staff has

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 AMR results, which the applicant claimed to be consistent with the GALL

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Report, are consistent with the AMRs in the GALL Report. Therefore, the staff finds that the

applicant has demonstrated that it will adequately manage the effects of aging for these

components 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).

On the basis of its audit and review, the staff concludes 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 for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.2 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 3.3.2.2 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

* 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

addresses the issues that were 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's audit and review report gives details of the staff's evaluation.

The GALL Report indicates that further evaluation is necessary for the aging effects described

in the following sections of this SER.

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3.3.2.2.1 -Loss of Material due to General, Pitting, and Crevice Corrosion

In LRA Section 3.3.2.2.1, the applicant addressed the loss of material in components'of the

SFP and cleanup system.

The applicant stated that the SFP cooling components do not provide any intended function

within the scope of license renewal. Aging management of the fuel pool assures pool inventory,

which, in turn, assures cooling. Section 3.5.2.2 of this report evaluates this along with the',

auxiliary building.

Because the spent fuel cooling components do not provide any intended function that requires

aging management, the staff finds this to be acceptable.

The staff finds that the applicant has demonstrated -that it will adequately manage the effects of

aging for components of the SFP system subject to the loss of material so that the'intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.3.2.2.2 Hardening and Cracking or Loss of Strength due to Elastomer Degradation or Loss of

Material Due to Wear

In LRA Section 3.3.2.2.2, the applicant addressed the potential for the 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 SFP 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 SFP system contains no components with elastomers that are

subject to an AMR. For the ventilation systems, the applicant uses the plant-specific AMP

B.1.25, "Preventive Maintenance," to manage degradation of elastomers. Section 3.0.3.3.10 of

this SER documents the staff's evaluation of this program. For other systems, the applicant

uses one of three programs to manage elastomer degradation-the Preventive Maintenance

Program (CNP, AMP B.1.25), the Service Water System Reliability Program (CNP AMP

B.1.29), or the Fire Protection Program (CNP.AMP B.1.11). Sections 3.0.3.2.5 and 3.0.3.2.6

(for the Fire Protection Program) and Section 3.0.3.2.11 (for the Service Water System

Reliability Program) of this SER document the staff's evaluation of these programs.

RAI 3.3.2-3 . . - -

The staff requested clarification of the method(s) used to monitor a change in material

properties of elastomers in the ventilation systems. Material properties that could affect the

performance of elastomers (e.g., hardness, flexibility) are not directly measured. By letter

-dated August 20, 2004, in RAI 3.3.2-3, the staff asked the applicant to provide a technical basis

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for the conclusion that degradation of elastomers will be detected before a loss of intended

function of the component occurs or to explain why the elastomers are not subject to hardening

and flexibility aging effects.

In its response dated September 2, 2004, the applicant stated that hardness and flexibility are

not critical properties for maintaining the pressure boundary intended function. The applicant

further stated that should the elastomer become excessively hard or brittle, visible cracking

would result, which the applicant would detect and correct before degradation and loss of

intended function would occur. Finally, the applicant stated that it will perform the visual

examinations of elastomer components of ventilation systems at an inspection interval sufficient

to identify degradation before a loss of pressure boundary function would occur.

On the basis of its review of the applicant's response to RAI 3.3.2-3, the staff finds that the

applicant demonstrated that it will adequately manage hardening and cracking or loss of

strength due to elastomer degradation of ventilation system components so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.3.2.2.3 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.

3.3.2.2.4 Crack Initiation and Growth due to Cracking or Stress-Corrosion Cracking

The staff reviewed LRA Section 3.3.2.2.4 against the criteria in SRP-LR Section 3.3.2.2.4.

In LRA Section 3.3.2.2.4, the applicant addressed the potential for cracking in the high-pressure

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

adequate management of these aging effects.

The applicant used the plant-specific Preventive Maintenance Program (CNP AMP B.1.25) to

manage cracking of the charging pump casings. Section 3.0.3.3.10 of this SER documents the

staff's evaluation of this program. This program was evaluated as an acceptable response to

NRC IN 80-38 for monitoring this aging effect, and on that basis, it is acceptable to the staff.

The staff 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, as required by 10 CFR 54.21 (a)(3).

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3.3.2.2.5 Loss of Material due to General, Microbiologically Influenced, Pitting, and Crevice

Corrosion

In LRA Section 3.3.2.2.5, the applicant addressed the loss of material from 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 the 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 and 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 EDG system.

Loss of material due to general, pitting, and crevice corrosion and MIC could occur in the duct

fittings, access doors, 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 100 0C (212 'F) in the ventilation systems. The GALL Report recommends further

evaluation to ensure adequate management of these aging effects.

For managing loss of material from surfaces exposed to air and outdoor air, the applicant

credited the System Walkdown Program (CNP AMP B.1.38), evaluated in Section 3.0.3.3.14 of

this SER; the System Testing Program (CNP AMP B.1.37), evaluated in Section 3.0.3.3.13; the

Service Water System Reliability Program (CNP AMP B.1.29), evaluated in Section 3.0.3.2.11;

and the Preventive Maintenance Program (CNP AMP B.1.25), evaluated in Section 3.0.3.3.10.

The applicant uses its Fire Protection Program (CNP AMP B.1.1 1) to manage the loss of

material for internal surfaces of the FP system. Sections 3.0.3.2.5 and 3.0.3.2.6 of this SER

document the staff's evaluation of Fire Protection Programs.

The staff reviewed CNP operating experience and confirmed that the applicant had exploited

sufficient opportunities for inspection. Because the inspection guidance provided assurance

that the applicant would identify the presence and extent of these aging effects, the staff finds

management of this aging effect to be acceptable.

The staff 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, as required by 10 CFR 54.21(a)(3).

3.3.2.2.6 Loss of Material due to General, Galvanic, Pitting, and Crevice Corrosion

In LRA Section 3.3.2.2.6, the applicant addressed further evaluation of programs to manage the

loss of material in the RCP oil collection system to verify.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 FP. The Fire Protection Program relies on a combination of visual and

volumetric examinations in accordance with the guidelines of Appendix R to 10 CFR Part 50

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and BTP 9.5-1 to manage the loss of material from corrosion. However, corrosion may occur at

locations where water from washdowns may accumulate. Therefore, the applicant should verify

the effectiveness of the program to ensure that corrosion is not occurring.

The GALL Report recommends further evaluation of programs to manage the loss of material

due to general, galvanic, pitting, and crevice corrosion to verify 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.

This inspection would be part of a program consistent with GALL AMP XL.M32.

In the LRA, the applicant stated that it will use the plant-specific Preventive Maintenance

Program (CNP AMP B.1.25) and, consistent with the GALL Report with enhancements, its Boric

Acid Corrosion Prevention Program (CNP AMP B.1.4) to manage the loss of material in lieu of

the one-time inspection. Sections 3.0.3.3.10 and 3.0.3.2.1, respectively, of this SER document

the staff's evaluation of the Preventive Maintenance and Boric Acid Corrosion Prevention

Programs. Because these programs will afford an opportunity to inspect similar material in this

environment, the staff finds that they will allow adequate verification of the effectiveness of the

management of the loss of material due to general, pitting, galvanic, and crevice corrosion.

The staff 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, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.7 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion and Biofouling

In LRA Section 3.3.2.2.7, the applicant addressed further evaluation of programs to manage the

loss of material in the diesel fuel oil system to verify the effectiveness of the Diesel Fuel

Monitoring Program.

Section 3.3.2.2.7 of the SRP-LR states that the loss of material due to general, pitting, and

crevice corrosion, MIC, and biofouling could occur on the internal surface of tanks in the diesel

fuel oil system and that loss of material due to general, pitting, and crevice corrosion and MIC

could occur in the tanks of the diesel fuel oil system in the EDG system. The existing AMP

relies on the Fuel Oil Chemistry Program for monitoring and controlling fuel oil contamination in

accordance with the guidelines of ASTM Standards D4057, D1796, D2709, and D2276 to

manage the 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 is necessary to ensure that corrosion is not occurring. The GALL Report

recommends further evaluation of programs to manage corrosion/biofouling to verify their

effectiveness. 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 will

maintain its intended function during the period of extended operation.

The GALL Report recommends programs consistent with GALL AMP XI.M30 and XL.M32 for

management of this aging effect.

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The applicant used CNP AMP B.1.10, 'Diesel Fuel Monitoring," evaluated in Section 3.0.3.2.4

of this SER, to manage the loss of material for the diesel fuel oil system. This program also

provides for the periodic inspection of the fuel oil tanks. The applicant took exception to -

ultrasonic testing of the diesel fuel oil tank, which addresses the one-time inspection

recommendation in the GALL Report.

During the audit, the staff requested a basis for the exception to ultrasonic testing. In response,

the applicant provided the results of ultrasonic testing that had already been performed arid the

basis for concluding that the management of the aging'effect will maintain the intended function

beyond the period of extended operation. After reviewing the data and the basis, the staff finds

that the applicant has already demonstrated the effectiveness of the program credited,'which is

an acceptable basis for the exception.

The staff finds that the Diesel Fuel Monitoring Program adequately manages the loss of -

material for carbon steel components in a fuel oil environment. The staff 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, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.8 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 AssuranceProgram.

3.3.2.2.9 Crack Initiation and Growth Due to Stress-Corrosion Cracking and Cyclic Loading

In LRA Section 3.3.2.2.9, the applicant addressed further evaluation of programs to manage

cracking in the CVCS to verify 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 Control Program relies on monitoring and control of water chemistry'based on'the

guidelines of EPRI TR-1 0571 4, "PWR Primary Water Chemistry Guidelines: Revision 4," to

manage the effects of crack initiation and growth due to SCC and cyclic loading. The applicant

should verify 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 from SCC and cyclic loading for these systems to verify the

effectiveness of the Water Chemistry Control 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 GALL AMP XI.M2 and a plant-specific verification program for

management of this aging effect'. -

The GALL Report recommends that the Water Chemistry Control Program be augmented by

verifying the absence of cracking due to SCC and cyclic loading, or the loss of material due to

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pitting and crevice corrosion. The GALL Report states that an acceptable verification program

should include temperature and radioactivity monitoring of the shell-side water and eddy-current

testing of tubes.

In the LRA, the applicant stated that it will manage this aging effect using its Water Chemistry

Control-Closed-Cycle Cooling Water Chemistry Control Program (CNP AMP B.1.40.2),

supplemented with the Heat Exchanger Monitoring Program (CNP AMP B.1.13). Sections

3.0.3.2.16 and 3.0.3.3.5 of this SER, respectively, document the staff evaluation of these

programs. The applicant also used the Water Chemistry Control-Chemistry One-Time

Inspection Program (CNP AMP B.1.41). Section 3.0.3.3.17 of this SER documents the staff's

evaluation of the Chemistry One-Time Inspection Program.

The staff finds that the Heat Exchanger Monitoring Program provides an acceptable way to

monitor the effectiveness of the Water Chemistry Control Program. The staff 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, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.10 Reduction of Neutron-Absorbing Capacity and Loss of Material due to General

Corrosion

In LRA Section 3.3.2.2.10, the applicant addressed the reduction of neutron-absorbing capacity

and loss of material due to general corrosion, which could occur in the neutron-absorbing

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 used the Boral Surveillance Program (CNP AMP B.1.3) and the Water Chemistry

Control-Primary and Secondary Water Chemistry Control Program (CNP AMP B.1.40.1) to

manage neutron-absorbing capacity and loss of material. Sections 3.0.3.3.3 and 3.0.3.2.15 of

this SER, respectively, document the staff's evaluation of these programs. The staff finds the

use of the Boral Surveillance and Water Chemistry Control Programs acceptable for mitigating

this aging effect. The staff 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, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.11 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

In LRA Section 3.3.2.2.11, 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 the 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 (service water system) and in the diesel fuel oil system. The Buried

Piping and Tanks Inspection Program relies on industry practice, frequency of pipe excavation,

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and operating experience to manage the effects of the loss of material from general, pitting,-

and crevice corrosion and MIC. The effectiveness of the Buried Piping and Tanks Inspection

Program should be verified to evaluate an applicant's inspection frequency and operating

experience with buried components, thus ensuring that the loss of material is not occurring.-

The GALL Report recommends AMP XL.M34 for management of this aging effect.

The applicant stated in the LRA that the CNP ESW system has no buried components. To

manage the loss of material for buried components of the diesel fuel oil system, the applicant

credited CNP AMP B.1.6, "Buried Piping Inspection," which the staff evaluates in Section

3.0.3.2.2 of this SER. The program calls for the opportunistic inspection of buried pipe when

excavated. The staff reviewed the applicant's operating history and find that the frequency of

pipe excavation is sufficient to allow the applicant to manage the effects of loss of material in

this manner.

The staff finds that the applicant has demonstrated that it will adequately manage the effects of

aging for the loss of material 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).

Conclusion

On the basis of its review, 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 determined that the applicant has adequately

addressed the issues that received further evaluation. In addition, the staff reviewed the

applicant's further evaluations against the criteria contained in Section 3.4.2.2 of the SRP-LR.

The staff 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, as required by 10 CFR 54.21 (a)(3).

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

GALL Report

Summary of Technical Information in the Application

In Tables 3.3.2-1 through 3.3.2-11 of the LRA, the staff reviewed additional details of the results

of the AMRs for material, environment, AERMs, 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 the GALL

Report evaluates neither the identified component nor the material and environment -

combination. The applicant also provided information concerning how it will manage the

AERMs.

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.

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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.

Staff Evaluation

For component type, material, and environment combinations that are not evaluated in the

GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant

had 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 as

required by 10 CFR 54.21 (a)(3). The following sections discuss the staff evaluation.

3.3.2.3.1 Spent Fuel Pool System

Staff Evaluation

The staff reviewed the AMR of the SFP system component, material, environment, and AERM

combinations that are identified in the sections below titled "Aging Effects" and 'Aging

Management Programs." The applicant identified these combinations in LRA Table 3.3.2-1.

For the combinations, the staff verified 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 they adequately describe the programs.

Aging Effects

Table 2.3.3-1 of the LRA lists individual system components that are within the scope of license

renewal and are subject to an AMR. The component type evaluated in this section includes

SFP poison.

For this component type, the applicant identified the following materials, environments, and

AERMs:

* Aluminum exposed to an internal and external borated treated water environment is

subject to cracking.

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effect of the above SFP system component type is consistent with industry experience for this

combination of material 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 component in the SFP system.

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Aging Management Programs

After evaluating the applicant's identification of the aging effect for the above component type,

the staff evaluated the AMP to determine if it is appropriate for managing the identified aging

effect. The staff also verified that the UFSAR Supplement adequately describes the program.

Table 3.3.2-1 of the LRA identifies the CNP Water Chemistry Control Program as managing the

aging effect described above for the SFP system. The staff's detailed review of this AMP

appears in Section 3.0.3.3.16 of this SER. During its review, the staff determined that it needed

additional information to complete its evaluation.

RAI 3.3.2.1.1-1

The applicant's Water Chemistry Control-Auxiliary Systems Water Chemistry Control Program

(CNFP B.1.40.3) (page B-128 of the LRA) states the program's purpose as managing the loss of

material and fouling. The program description further states that it does not provide for the

detection of aging effects, such as the loss of material and cracking. Table 3.3.2-1 of the LRA.

(page 3.3-32) identifies cracking as a SFP poison aging effect and the Water Chemistry Control

Program as the applicable AMP. In RAI 3.3.2.1.1-1, the staff asked the applicant to identify the

AMP used to manage cracking of SFP poison and provide justification that the program will

ensure that the component's intended function is maintained during the period of extended

operation.

By letter dated June 8, 2004, the applicant stated that the water in the SFP is included in the.

Primary and Secondary Water Chemistry Control Program (not the Auxiliary Systems Water

Chemistry Control Program). In LRA Section B.1.40.1, the applicant identified the Primary and

Secondary Water Chemistry Control Program as managing the cracking of components. Table

3.3.2-1 of the LRA (page 3.3-32) conservatively identifies cracking as an AERM since aluminum

alloys are susceptible to cracking from stress corrosion and IGA in corrosive environments with

high chloride concentrations. The Primary and Secondary Water Chemistry Program, which

controls SFP water quality by maintaining chemistry levels (i.e., chlorides, fluorides, and

sulfates) within acceptable limits, prevents this aging effect. Therefore, the Primary and

Secondary Water Chemistry Control Program is adequate to manage this aging effect for

aluminum, such that the boral will continue to maintain its component intended function through

the period of extended operation. Based on its review, the staff finds the applicant's response

to RAI 3.3.2.1.1-1 acceptable because the response clarifies water chemistry control of the SFP

and aging management of its related components susceptible to cracking; therefore, the staff's

concerns described in RAI 3.3.2.1.1-1 are resolved.

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 effect of the SFP system

component type that are addressed in this section. 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 SFP system

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I

components identified in this section. 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).

3.3.2.3.2 Essential Service Water System

Staff Evaluation

The staff reviewed the AMR of the ESW system component, material, environment, and AERM

combinations that are identified in the sections below titled "Aging Effects" and "Aging

Management Programs." The applicant identified these combinations in LRA Table 3.3.2-2.

For the combinations, the staff verified 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 they adequately describe the programs.

Aging Effects .

Table 2.3.3-2 of the LRA lists individual system components that are within the scope of license

renewal and are subject to an AMR. The component types evaluated in this section include

bolting, detector wells, expansion joints, fittings, flex hose, manifold (piping), orifices, piping,

thermowell, tubing, and valves.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Elastomer exposed to an external condensation environment is subject to change in

material properties and cracking. Elastomer exposed to an internal raw water (fresh)

environment is subject to change in material properties, cracking, and loss of material.

* For stainless steel and copper alloy exposed to external condensation, the applicant

identified no AERMs.

Section 3.3.2.3.12 presents the staff's evaluation of the loss of preload and cracking for closure

bolting.

On the basis of its review of the information in the LRA, the staff finds that the aging effects of

the above ESW component types are consistent with industry experience for this combination

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 component in the ESW system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for the above components, the

staff evaluated the AMP to determine if it is appropriate for managing the identified aging

effects. The staff also verified that the UFSAR Supplement adequately describes the program.

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Table 3.3.2-2 of the LRA identifies the Service Water System Reliability Program for-managing<

the aging effects described above for the ESW system. The staff's detailed review of this AMP

appears in Section 3.0.3.2.11 of this SER. During its review, the staff determined that it needed

additional information to complete its review.

RAI 3.3.2-2

The LRA states on page B-96 that the applicant will enhance the Service Water System

Reliability Program (CNP B.1.29) to check for evidence of selective leaching during visual

inspections. However, GALL Report AMP XLI.M33 recommends a visual inspection and a

hardness measurement of selected components to determine whether a loss of material due to

selective leaching is occurring. In RAI 3.3.2-2, the staff asked the applicant to justify excluding

a hardness measurement from the Service Water System Reliability Program to detect

selective leaching.

By letter dated June 8, 2004, the applicant stated that since the detection of selective leaching

is an enhancement to the Service Water System Reliability Program, specific details on the

methods for the detection of selective leaching are not available at this time. Implicit in the

current commitment to enhance the Service Water System Reliability Program is the

implementation of industry best practices. Current industry practices include visual inspections

and either hardness testing, as stated in GALL AMP XI.M33, or other inspection methods.;

Additionally, in the future, more effective techniques for the detection of selective leaching may

become available. Based on its review, the staff finds the applicant's response to RAI 3.3.2-2

acceptable, because the applicant committed to enhance the Service Water System Reliability

Program for the detection of selective leaching using industry best practices at the time of

implementation. -Therefore, the staff's concern described in RAI 3.3.2-2 is resolved. This is

Commitment #21 in Appendix A of this SER.

For stainless steel exposed to external condensation, the applicant identified no AERMs. The

component types affected are bolting, detector wells, fittings, flex hose, orifice, piping,

thermowell, tubing, and valve. Because the applicant did not identify any AERMs, the staff

finds that the absence of an AMP for stainless steel components exposed to condensation is

acceptable.

For copper alloy manifold (piping), piping, tubing, and valves exposed to condensation, the

applicant identified no AERM. No aging effects are considered to require management for - -

copper components exposed to condensation. Because the applicant did not identify any

AERMs, the staff finds that the absence of an AMP for copper components exposed to

condensation is 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 ESW system

components that are identified in this section. -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 Component Cooling Water System

Staff Evaluation

The staff reviewed the AMR of the CCW system component, material, environment, and AERM

combinations that are identified in the sections below titled "Aging Effects" and "Aging Management Programs." The applicant identified these combinations in LRA Table 3.3.2-3.

For the combinations, the staff verified 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 they adequately describe the AMPs.

Aging Effects

Table 2.3.3-3 of the LRA lists individual system components that are within the scope of license

renewal and are subject to an AMR. The component types evaluated in this section include

bolting, detector well, fittings, heat exchangers, heat exchanger (shell), heat exchanger (tubes), manifold (piping), piping, thermowells, tubing, and valves.

For the heat exchanger tubes component type, the applicant identified the following materials, environments, and AERMs:

* Copper alloy exposed to an external treated water environment is subject to loss of

material.

Section 3.3.2.3.12 of this SER contains the staff's evaluation of the loss of preload and cracking for closure bolting.

On the basis of its review of the information provided in the LRA, the staff finds that the aging effects of the component cooling water system component types are consistent with industry experience for this combination of material and environment. The staff did not identify any omitted aging effects. Therefore, the staff finds that the applicant has identified the appropriate aging effect for the material and environment associated with the above component of the

CCW system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for the above component types, - the staff evaluated the AMP to determine if it is appropriate for managing the identified aging effect. The staff also verified that the UFSAR Supplement adequately describes the program.

LRA Table 3.3.2-3 identifies the following AMP for managing the aging effect described above

for the heat exchanger tubes component type.

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Heat Exchanger Monitoring Program

The staff's detailed review of this AMP appears in Section 3.0.3.3.5 of this SER.

For stainless steel exposed to external condensation, the applicant identified no AERMs. The

component types' affected include bolting, detector well, fittings, heat exchanger, heat

exchanger (shell), manifold (piping), piping, thermowell, tubing, and valves. Because the

applicant did not identify any AERMs, the staff finds that the absence of an AMP for stainless

steel components exposed to condensation is acceptable.

For copper alloy fittings, manifold, piping, tubing, and valves exposed to condensation, the

applicant identified no aging effects that require management. Thus, the staff finds that the

absence of an AMP for copper components exposed to condensation is acceptable.

In the LRA, the applicant stated that it will manage loss of material from copper alloy fittings,

manifold, piping, tubing, and valves exposed to treated water by using the Closed Cooling

Water Chemistry Control Program. On the basis of industry operating experience with copper

alloy in a treated water environment, the staff finds this approach acceptable.

In the LRA, the applicant stated that it will manage loss of material for stainless steel exposed

to treated water in the CCW system by using the Water Chemistry Control-Closed Cooling

Water Chemistry Control program (CNP AMP B.1.40.2). This applies to detector well, fittings,

heat exchanger tubes, manifold, piping, thermowell, tubing, and valve component types. The

applicant stated that this program is consistent with GALL AMP XL.M21, with exceptions.

Section 3.0.3.2.16 of this SER documents the staff's evaluation of this program.

The staff reviewed stainless steel components exposed to treated water and concludes that the

effects of general, pitting, and crevice corrosion on stainless steel components are not

significant in chemically treated water. For this reason and because the Water Chemistry

Control Program is consistent with the GALL Report, the staff finds the applicant's approach

acceptable.

In the LRA,'the applicant stated that it will manage cracking of stainless steel exposed to

treated water in the CCW system with closed cooling water chemistry control. This applies to

fittings, manifold, piping, thermowell, tubing; and valve component types. The staff found that

the GALL Report does not include this material and environment combination for CCW

component types; however, it has been considered acceptable to manage the cracking ofstainless steel using water chemistry control supplemented by inspection or monitoring

programs. The staff asked the applicant to identify the program or programs that it will use to

confirm the effectiveness of water chemistry control for managing this aging effect,' or clarify the'

rationale for relying on water chemistry control alone. In the related RAI B.1.41-2, the staff

asked the applicant to provide a list of components, material types, environments, and aging

effects that it will inspect using the Water Chemistry Control-Chemistry One-Time Inspection.

Program (CNP AMP B.1.41) and to justify that the components selected constitute an adequate

sample size to verify the effectiveness of the Water Chemistry Control Program for each aging

effect to be managed. Section 3.0.3.3.17 of this SER provides the response to and staff

evaluation of RAI B.1.41-2.

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In the LRA, the applicant stated that it will manage the loss of material from stainless steel heat

exchanger component types (including shell and tubes) by using the Oil Analysis Program

(CNP AMP B.1.23). Section 3.0.3.3.8 of this SER documents the staff's evaluation of this

program.

Because the Oil Analysis Program maintains oil systems free of contaminants (primarily water

and particles), the staff finds that this program adequately manages the loss of material for

components exposed to lubricating oil, including stainless steel.

On the basis of its review of the information provided in the LRA, the staff finds the applicant

has identified the appropriate AMP for managing the aging effects of the component cooling

water system component types addressed in this section. 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 CCW system

components identified in this section. 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).

3.3.2.3.4 Compressed Air System

Staff Evaluation

The staff reviewed the AMR of the CA system component, material, environment, and AERM

combinations that are identified in the sections below titled "Aging Effects" and "Aging

Management Programs." The applicant identified these combinations in LRA Table 3.3.2-4.

For the combinations, the staff verified that the applicant identified all applicable AERMs and

credited appropriate AMPs with managing the AERMs. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that they adequately describe the AMPs.

Aging Effects

Table 2.3.3-4 of the LRA lists individual system components that are within the scope of license

renewal and are subject to AMR. The component types evaluated in this section include

bolting, fittings, flex hoses, piping, tanks, tubing, and valves.

For these component types, the applicant identified the following materials, environments, and

AERMs:

Stainless steel exposed to an internal treated air environment is subject to loss of

material.

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* Brass exposed to an internal environment of treated air is subject to loss of material.

* Elastomer exposed to an internal environment of treated air experiences change in

material properties and cracking. , :

* Copper alloy exposed to an internal treated air environment is subject to loss of

material.

Section 3.3.2.3.12 of this SER contains the staff's evaluation of the loss of preload and cracking

for closure bolting.

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effects of the above CA system 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 above components in the CA system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above component

types, 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.

Table 3.3.2-4 of the LRA identifies the following AMPs for managing the aging effects described

above for the CA system:

* Instrument Air Quality Program

* Preventive Maintenance Program.

The staff's detailed reviews of these AMPs appear in Sections 3.0.3.3.7 and 3.0.3.3.10 of this

SER, respectively.

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI 3.3.2.1.4-1

Table 3.3.2-4, page 3.3-49, of the LRA identifies change in material properties and cracking as

AERMs for elastomer flex hose components in an internal treated air environment. The

applicant credited the Preventive Maintenance Program (CNP AMP B.1.25, page B-82 of the

LRA) with managing these aging effects by periodic visual inspections and replacement as

necessary. It is not apparent from the program description if the flex hoses will be inspected

both internally and externally. The effectiveness of a visual inspection in detecting internal

changes in material properties and cracking is also not apparent. Therefore, in RAI 3.3.2.1.4-1,

the staff asked the applicant to justify that the Preventive Maintenance Program will adequately

identify and manage the identified internal aging effects.

By letter dated June 8, 2004, the applicant stated that the elastomer flex hoses listed in LRA

Table 3.3.2-4 are control air system rubber hoses located in containment. These hoses are

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exposed to treated air internally and ambient air externally. Degradation of rubber from

cracking and change in material properties can result from ultraviolet radiation, ionizing

radiation, or thermal exposure. The external and internal hose surfaces are exposed to the

same environmental conditions, with the exceptions that the air environments differ and the

internal hose surfaces are not exposed to ultraviolet radiation, since they are not exposed to

light. Since the external surface is exposed to an environment that is more severe than the

internal environment, the condition of the external surface would conservatively reflect the

condition of the internal surface. Therefore, the applicant stated that inspection of the external

surfaces is adequate to ensure detection of aging effects before loss of the pressure boundary

intended function occurs.

Based on its review, the staff does not find the applicant's response to RAI 3.3.2.1.4-1

acceptable. The applicant's response clarifies the specific elastomer control air components

requiring aging management, as well as the associated environmental conditions and

preventive maintenance activities. The applicant's response indicates that external

environmental conditions are more severe than the internal environmental conditions for the

components of concern. Based on these environmental conditions, the response indicates that

visual inspection of the external surface will successfully manage the associated aging of these

elastomer components and that inspection of the internal surface is not necessary. Aging of

elastomer components is a complex issue. The materials' specific chemical properties, as well

as environmental conditions, affect the rate of aging. As the applicant's response indicates,

internal and external environmental conditions are different, but the applicant's assumption that

the material aging will occur more rapidly and be more apparent at the external surface has not

been substantiated. A study by Sandia National Laboratory titled, "Prediction of Elastomer

Lifetimes from Accelerated Thermal Aging Experiments," by Kenneth T. Gillen and Roger L.

Clough, indicates that oxygen concentration, as well as pressure, affects oxidation of

elastomers. The applicant's response to RAI 3.3.2.1.4-1 did not provide adequate information

to justify aging management of these components by external visual observation only. The

staff has asked the applicant to substantiate the adequacy of external surface visual

examination in managing aging by providing details related to the applicable component's

inspection/failure/repair frequency during the plant's operating history. In addition, CNP AMP

B.1.25 does not provide an inspection frequency for the hoses such that the intended function

will be maintained.

By letter dated October 18, 2004, the applicant stated that a review of the operating experience

for these hoses did not identify any pressure boundary failures due to elastomer degradation.

However, prior to the period of extended operation, I&M will inspect internal hose ends and

external surfaces of the in-containment control air system rubber hoses referred to in LRA

Table 3.3.2-4. The periodicity of future inspections will be based on the condition of the hoses

in relation to their time in service. Based on its review, the staff finds the applicant's assessment

of operating history and conditions for verification and future inspections acceptable for

managing the aging effects to the hoses; therefore, the staff's concern described in RAI

3.3.2.1.4-1 is resolved.

For stainless steel exposed to ambient air, the applicant did not identify any AERMs. The

component types affected are bolting, flex hose, piping, tubing, and valves. Because the

applicant identified no AERMs, and this is consistent with industry experience, the staff finds the

absence of an AMP for stainless steel components exposed to ambient air to be acceptable.

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For brass fittings and valve component types exposed to ambient air (external) or nitrogen

(internal), the applicant identified no AERMs. Because the applicant did not identify any

AERMs, and this is consistent with industry experience, the staff finds the absence of an AMP

for brass components exposed to ambient air or nitrogen to be acceptable.

In the LRA, the applicant stated that it will manage the cracking and change of material

properties of elastomers of the flex hose component type in ambient air by using the Preventive

Maintenance Program (CNP AMP B.1.25). The staff evaluation of this program appears in .

Section 3.0.3.3.10 of this SER. The staff only found documentation -of visual inspection, which

is an acceptable method for the detection of cracking. The staff asked the applicant to clarify

the method(s) used to monitor a change in material properties of elastomers in the flex hose

associated with the CA system. Material properties that could affect the performance of

elastomers (e.g., hardness, flexibility) are not directly measured.

RAI 3.3.3-2

By letter dated August 20, 2004, in RAI 3.3.3-2, the staff asked the applicant to provide a basis

for concluding that it will identify degradation of the elastomers before the intended function is

compromised, or to provide a technical basis for the conclusion that the elastomers in question

are not subject to these aging effects.

In its response dated September 2, 2004, the applicant stated that it will verify the flexibility of

the hoses through physical manipulation of the hose during the visual inspection, thereby

enhancing the inspector's ability to sense (both visually and through touch) a change in material

properties that could affect the performance of the elastomers. The applicant stated that the

Preventive Maintenance Program will use appropriate examination methods to ensure the

identification of any degradation of flexible hoses in the CA system before the intended function

is compromised.

On the basis of its review of the applicant's response to RAI 3.3.3-2, the staff finds that the

applicant has demonstrated that it will adequately manage change in material properties

resulting from the hardening and flexibility of flexible hoses in the CA system so that the

intended function will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3). -

For steel components exposed to nitrogen, the applicant identified no AERMs. The component

types affected are carbon steel piping, tank, tubing, and valves, as well as stainless steel

piping, tubing, and valves. Because the applicant did not identify any AERMs, and this is

consistent with industry experience, the staff finds the absence of an AMP for steel components

exposed to nitrogen to be acceptable.

In the LRA, the applicant stated that it will manage loss of material from carbon steel piping,

tank tubing, and valve component types, when exposed to treated air, using CNP AMP B.1.19,

"Instrument Air Quality." The staff evaluation of this program appears in Section 3.0.3.3.7 of

this SER. Because plant operating experience demonstrates that the Instrument Air Quality

Program is adequate to satisfy the requirements of GL 88-14, this approach is acceptable to

the staff.

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For copper alloy piping, tubing, and valves exposed to ambient air, the applicant identified no

AERMs. Because the applicant did not identify any AERMs, and this is consistent with industry

experience, the staff finds the absence of an AMP for copper alloy components exposed to

ambient air to be acceptable.

For stainless steel exposed to nitrogen, the applicant identified no AERMs. The component

types affected are piping, tubing, and valves. Because the applicant did not identify any

AERMs, and this is consistent with industry experience, the staff finds the absence of an AMP

for stainless steel components exposed to nitrogen to be acceptable.

On the basis of its review of the information provided in the LRA and supplemental information

provided by the applicant, the staff finds the applicant has identified appropriate AMPs for

managing the aging effects of the compressed air system component types that are addressed

in this section. 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 compressed air

system components that are identified in this section. 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

Staff Evaluation

The technical staff reviewed the AMR of the CVCS component, material, environment, and

AERM combinations that are identified in the sections below titled "Aging Effects" and "Aging

Management Programs." The applicant identified these combinations in LRA Table 3.3.2-5.

For the combinations, the staff verified 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 they adequately describe the AMPs.

Aging Effects

Table 2.3.3-5 of the LRA lists individual system-components that are within the scope of license

renewal and are subject to an AMR. The component types evaluated in this section include

bolting, filter housing, flow element body, heat exchanger (bonnet), heat exchanger (shell), heat'

exchanger (tubes), heater housing, level glass gauge, manifold (piping), orifices, piping, pipingspool assembly, pulsation dampener, pump casing, strainer-tee, tanks, thermowell, tubing, and

valves.

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For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel exposed to an external air environment is subject to loss of material and

loss of mechanical closure integrity. Carbon steel exposed to an internal treated water

environment is subject to loss of material.

* Stainless steel exposed to an external treated (borated) water greater than 132 0C (270

'F) environment is subject to loss of material-wear, loss of material-erosion,-and

cracking-fatigue.

* Glass exposed to an internal environment of treated (borated) water experiences no

aging effects.

Section 3.3.2.3.12 provides the staff's evaluation of loss of preload and cracking for closure

bolting.

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI 3.3.2.1.5-1

Table 3.3.2-5 of the LRA (page 3.3.62) identifies the Boric Acid Corrosion Prevention Program

(CNP AMP B.1.4) as managing the loss of material on the internal surface of a carbon steel

tank in an air environment. The program description states that the applicant performs periodic

visual inspections of components on which borated reactor water may leak. In RAI 3.3.2.1.5-1,

the staff asked the applicant to explain how the visual inspection referred to in the Boric Acid

Corrosion Prevention Program will adequately identify and manage the internal aging effects for

the tank.

By letter dated June 8, 2004, the applicant stated the following:

The tanks with carbon steel surfaces that are included in the component type

'Tank" listed in the LRA Table 3.3.2-5 are the volume control and boric acid

tanks. These tanks are primarily stainless steel, but the manway external cover

and some external welded sub-components, such as the tank support legs, are

carbon steel. The carbon steel manway cover has a stainless steel liner that

-protects the carbon steel from contact with borated water. As identified in LRA

Table 3.3.2-5, the inside surface of the stainless steel liner is subject to an air

(internal) and treated borated water (internal) environment, and will be included

- in the scope of the Water Chemistry Control Program. LRA Table 3.3.2-5 also

correctly indicates that the external carbon steel tank sub-components (i.e., the

manway cover and other welded sub components, such as the tank support

legs) are subject to an air (external) environment, and are included in the scope

of the Boric Acid Corrosion Prevention and System Walkdown Programs. The

air (internal) environment on carbon steel is conservatively considered to be

applicable to inside surface of the manway cover, which is protected from the

treated borated water environment by the stainless steel liner. The Boric Acid

Corrosion Prevention Program is applicable because the carbon steel

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subcomponents are in an air environment with the potential for exposure to

borated water leakage.

Based on its review, the staff does not find the applicant's response to RAI 3.3.2.1.5-1

acceptable. The applicant's response clarifies the tank design in relationship to the carbon

steel internal components referenced in LRA Table 3.3.2-5, page 3.3.62. From this new

information provided by the applicant, the staff cannot determine how the Boric Acid Corrosion

Prevention Program will detect the loss of liner integrity and subsequent degradation of the

carbon steel manway. The applicant should explain how the visual inspection referred to in the

Boric Acid Corrosion Prevention Program will identify the loss of tank manway cover liner

integrity and subsequent degradation of the carbon steel internal surface. The staff's concern

focuses on the following part of the applicant's response:

The air (internal) environment on carbon steel is conservatively considered to be

applicable to inside surface of the manway cover, which is protected from the

treated borated water environment by the stainless steel liner. The Boric Acid

Corrosion Prevention Program is applicable because the carbon steel

subcomponents are in an air environment with the potential for exposure to

borated water leakage.

The staff interprets this to indicate that the applicant has conservatively included the carbon

steel material that is lined with stainless steel (manway cover) to possibly address aging from

the leakage of boron, should the liner fail. Further, the applicant apparently took credit for the

Boric Acid Corrosion Prevention Program to manage this aging effect. If this interpretation is

correct, it is unclear how an external inspection of the manway will detect the loss of the

stainless steel liner integrity and the resulting carbon steel degradation.

During the September 1, 2004 meeting, the applicant showed a diagram of the manway cover.

It is a carbon steel blind flange located on the external side on a tank. The surface of the blind

flange internal to the tank is lined with stainless steel. The applicant explained that the Boric

Acid Corrosion Prevention Program would be used to detect degradation on the external carbon

steel portion of the flange only. The Boric Acid Corrosion Prevention Program does not

address the internal portion of the flange. The applicant stated that the Water Chemistry

Control Program is used to detect the loss of the internal stainless steel liner integrity. The staff

finds the applicant's clarification of this issue provided during the meeting and documented in

the meeting minutes to be adequate. Based on its review, the staff finds the applicant's

explanation of the flange configuration and applicability of appropriate AMPs acceptable to

resolve all questions staff has associated with RAI 3.3.2.1.5-1. Therefore, the staff's concern

described in RAI 3.3.2.1.5-1 is 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 RAI, the staff finds that the aging effects of

the above chemical and volume control system 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 above component types in

the CVCS.

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Aging Management Programs!

After evaluating the applicant's identification of aging effects for each of the above component

types, 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.

Table 3.3.2-5 of the LRA identifies the following AMPs for managing the aging effects described

above for the CVCS:

* Boric Acid Corrosion Prevention Program

* System Walkdown Program

* 1 TLAA-Metal Fatigue Program

* ~-Heat Exchanger Monitoring Program

* ' System Testing Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.2.1, 3.0.3.3.14, 4.3,

3.0.3.3.5, and 3.0.3.3.13 of this SER, respectively.

In the LRA, the applicant identified no aging effect for stainless steel bolting, filter housing, flow

element body, heat exchanger (bonnet), heat exchanger (shell), heater housing, manifold

(piping), orifice, piping, piping-spool assembly, pulsation damper, pump casing, strainer (tee),

tank, thermowell, tubing, and valve component types exposed to air. Because the applicant did,

not identify any AERMs, and this is consistent with industry experience, the staff finds the

absence of an AMP for stainless steel components exposed to ambient air to be acceptable. -

In the LRA, the applicant stated that it will manage loss of material for stainless steel in treated,

borated water using its Water Chemistry Control-Primary and Secondary Water Chemistry

Control Program (CNP AMP B.1.40.1). This applies to the filter housing, flow element body,

heat exchanger (bonnet, shell, and tubes), heater housing, manifold (piping), orifice, piping,

piping spool assembly, pulsation dampener, pump casing, strainer-tee, tank, thermowell,

tubing, and valve component types in the CVCS. Section 3.0.3.2.15 of this SER documents the

staff's evaluation of this program.

The GALL Report does not identify this material and environment combination for this system.

Because stainless steel components are not subject to significant general, pitting, and crevice

corrosion in treated, borated water, the staff finds this approach acceptable. '- -

In the LRA, the applicant stated that it will use the Water Chemistry Control Program to manage

fouling of stainless steel heat exchanger tubes in treated, borated water. The GALL Report

does not identify this aging effect for this component, material, and environment combination.

The staff finds the use of the Water Chemistry Control Program to be acceptable.

In the LRA, the applicant stated that it will use the Water Chemistry Control Program to manage

cracking of stainless steel in treated, borated water.- This affects orifice, piping, thermowell,

tubing, and valve component types in the CVCS.- On the basis that this approach is similar to

the management of cracking of stainless steel in this environment in other non-Class 1

systems, the staff finds the use of the Water Chemistry Control Program to be acceptable for

these components.

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In the LRA, the applicant stated that it identified no aging effects for stainless steel piping and

valves exposed to an environment of hydrogen or nitrogen gas. Because the applicant did not

identify any AERMs, and this is consistent with industry experience, the staff finds the absence

of an AMP for stainless steel components exposed to a hydrogen or nitrogen gas environment

to be acceptable.

In the LRA, the applicant stated that there are no aging effects for the level glass gauge

component type (glass) in an internal environment of treated (borated) water. The GALL

Report does not discuss similar component, material, and environment combinations. On the

basis that these components have no AERMs, the staff finds the absence of an AMP for glass

to be 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 CVCS component types that

are addressed in this section. 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 CVCS

components that are identified in this section. 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 Heating, Ventilation, and Air Conditioning Systems

Staff Evaluation

The staff reviewed the AMR of the heating, ventilation, and air conditioning (HVAC) system

component, material, environment; and AERM combinations that are identified in the sections

below titled "Aging Effects" and "Aging Management Programs." The applicant identified these

combinations in LRA Table 3.3.2-6. For the combinations, the staff verified 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 they adequately describe the programs.

Aging Effects

Table 2.3.3-6 of the LRA lists individual system components that are within the scope of license

renewal and are subject to an AMR. The component types evaluated in this section include

bolting, dryer, heat exchanger (shell), heat exchanger (tubes), heater housing, piping, sight glass, sight glass housing, tanks, test canister housing, thermowells, tubing, valves, and

ventilation unit housing.

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For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel exposed to an internal air environment is subject to loss of material.

* Stainless steel exposed to an external condensation environment is subject to fouling,

loss of material, and loss of material-wear.

* Copper alloy exposed to an external condensation environment is subject to loss of

material or loss of material-wear.

* Copper alloy exposed to an external environment of Freon experiences loss of

material-wear. Copper alloy exposed to an external environment of condensation

experiences the aging effect of fouling.

* Copper alloy exposed to an external environment of raw water (fresh) or treated water

experiences the aging effects loss of material and loss of material-wear.

* Glass exposed to condensation, Freon, or treated water environments experiences no

aging effects.

Section 3.3.2.3.12 provides the staff's evaluation of the loss of preload and cracking for closure

bolting.

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI 3.3.2-1

In LRA Tables 3.3.2-1 through 3.3.2-11 for the auxiliary systems, the applicant listed several

components having environments and applicable aging effects with associated AMPs. In the

same columns, for the same component, material, and environment, the applicant listed no

aging effects and no AMPs. For example, Table 3.3.2-11, page 3.3-130, identifies stainless

steel bolting with a function of pressure boundary exposed to an external environment of air as

experiencing loss of material managed by the Bolting and Torquing Activities Program. The

same item in the table on page 3.3-130 for the same component exposed to the same

environment has no aging effects and therefore no AMP. In addition, Table 3.3.2-6, page

3.3-77, shows that copper alloy valves exposed to an external condensation environment

experience loss of material. The same item in the table on page 3.3-77 for the same

component exposed to the same environment has no aging effects and therefore no AMP. In

RAI 3.3.2-1, the staff asked the applicant to explain these contradictory entries in the LRA

tables.

By letter dated June 8, 2004, the applicant provided the following response applicable to the

HVAC system for RAI 3.3.2-1:

In LRA Tables 3.3.2-1 through 3.3.2-11 for the auxiliary systems, there are six

,instances in which a component type lists both an aging effect and "none" for the

same material/environment combination. While this appears contradictory where

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occurring, it is not because each component type in the table actually represents

more than one component in the system. While the components are exposed to

the same overall environment, specific conditions for individual components differ. The following paragraphs provide additional information for the instances

applicable to the heating, ventilation, and air conditioning system:

*LRA Table 3.3.2 6, Heating, Ventilation, And Air Conditioning Systems (Page 3.3-77)-copper alloy valves exposed to external condensation

Copper alloy valves associated with the auxiliary feed pump room ventilation

may be wetted by condensation that could contain sulfates, chlorides, or

fluorides. Therefore, loss of material was identified as an aging effect requiring

management for these copper alloy valves exposed to condensation. Copper alloy valves within the control room liquid chiller packages may be wetted by condensation. However, since these components are in a clean, air-conditioned

environment, the condensation should not contain sulfates, chlorides, or

fluorides. Therefore, no aging effects requiring management were identified for

these copper alloy valves exposed to condensation.

The staff finds the applicant's response to RAI 3.3.2-1 acceptable because each component

type in the table actually represents more than one component in the system, and while the

components are exposed to the same overall environment, specific conditions for individual

components differ as discussed by the applicant; therefore, the staff's concerns described in

RAI 3.3.2-1 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 RAI 3.3.2-1, the staff finds that the aging effects of the

above HVAC system 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 above components in the HVAC

system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above component types, 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.

Table 3.3.2-6 of the LRA identifies the following AMPs for managing the aging effects described

above for the HVAC system:

* Preventive Maintenance Program

* Heat Exchanger Monitoring Program

* Service Water System Reliability Program

* Water Chemistry Control Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.10, 3.0.3.3.5, 3.0.3.2.11,

and 3.0.3.3.16 of this SER, respectively.

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For'stainless steel components exposed to air (external or internal surface), condensation

(external surface), or outdoor air (external surface), the applicant identified no aging effects.

Component types addressed include bolting,' piping, sight glass housing, tank, thermowell,

valves, and the ventilation unit housing. The staff finds this acceptable.

Because the applicant did not identify any AERMs, the staff finds the absence of an AMP for

stainless-steel components exposed to condensation to be acceptable.

The applicant identified no aging effects for copper-alloy component types exposed to Freon,

including the dryer, heat exchanger'tubes, piping; sight glass housing, tubing, and valves.

Because the applicant did not identify any AERMs for these components, the staff finds'the

absence of an AMP for copper-alloy components exposed to Freon to be acceptable'.'

In the LRA, the applicant stated that it will use its'Water Chemistry Control-Auxiliary Systems

Water Chemistry Control Program (CNP AMP B.1.40.3) to manage the fouling of copper alloy

and stainless steel heat exchanger tubes in treated water. This applies to the heat exchanger'

(tubes) component type in the HVAC systems.' The staff documents its evaluation of this

program in Section 3.0.3.3.16 of this SER.-

In the LRA, the applicant stated that it will use its Water Chemistry Control-Auxiliary Systems

Water Chemistry Control Program (CNP AMP B.1.40.3) to manage the loss of material for -,'

stainless steel in treated water. This applies to the heat exchanger (tubes), piping, sight glass

housing,-tank, thermowell, and valve componeent types in the HVAC systems.' The'staff

documents its' evaluation of this program in Section 3.0.3.3.16 of this SER.

For copper-alloy components exposed to air, including the heater housing, piping, sight glass

housing, test canister housing, and valves, the applicant identified no aging effects that require

aging management. Because the applicant did not identify any AERMs, the staff finds the

absence'of an AMP for copper components exposed to condensation to be acceptable.

In the CNP LRA, the applicant identified no aging effects'for copper alloy piping and valve

component types exposed to condensate. For the valve component type, the applicant did

identify loss of material as an AERM for copper alloy material exposed to condensate. The

staff asked the applicant to clarify the inconsistency between identical material and environment

combinations.

By letter dated June 8, 2004, in response to the'related RAI 3.3.2-1, the applicant stated that

copper alloy valves associated with the auxiliary feed pump ventilation may be wetted by

condensation that could contain sulfates, chlorides, or fluorides. In those cases, the applicant

identified loss of material as an AERM.' In other cases, the applicant stated that copper alloy

valves within the control room liquid chiller packages may be wetted by condensation that does

not contain sulfates, chlorides, or fluorides, and these specific valves do not have an AERM.

On the basis of its review of the response to RAI 3.3.2-1, the staff finds the issue resolved

because the applicant appropriately identified and distinguished between the AERMs for the

condensate environment containing sulfates, chlorides; or fluorides and the condensate

environment not containing those constituents. -

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In the LRA, the applicant stated that it will manage loss of material from a carbon steel valve

exposed to air internally through the System Walkdown Program (CNP AMP B.1.38). The staff

documents its evaluation of-this program in Section 3.0.3.3.14 of this SER.

In the related RAI 3.3.2.1.11-3, by letter dated May 26, 2004, the staff asked the applicant to

explain how the System Walkdown Program will detect the loss of material on the internal

surfaces of the several components. Section 3.3.2.3.11 of this SER provides the response to

and staff evaluation of RAI 3.3.2.1.11-3.

In the LRA, the applicant stated that there are no aging effects for the sight glass component

type (glass) in an external environment of condensation, or an internal environment of Freon or

treated water. The GALL Report does not discuss similar component, material, and

environment combinations. On the basis that these components have no AERMs, the staff

finds the absence of an AMP for glass to be acceptable.

On the basis of its review of the information provided in the LRA and the above RAI responses,

the staff finds the applicant has identified appropriate AMPs for managing the aging effects of

the HVAC system component types that are addressed in this section. 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 HVAC system

components that are identified in this section. 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 Fire Protection System

Summary of Technical Information in the Application

In Section 3.3.2.1.7 of the LRA, the applicant identified the materials, environments, AERMs

and AMPs for the FP system components.

In Table 3.3.2-7 of the LRA, the applicant provided a summary of AMRs for the FP system

components and identified which AMRs it considered to be not consistent with the GALL

Report.

Staff Evaluation

The staff reviewed LRA Section 3.3.2.1.7; LRA Table 3.3.1 Items 18 through 22 and Item 30;

and Table 3.3.2-7 to determine whether the applicant demonstrated that it will adequately

manage the effects of aging for the FP system during the period of extended operation, as

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required by 10 CFR 54.21 (a)(3). The staff conducted its review, described below, in accordance,

with Section 3.3 of the SRP-LR and the GALL Report.

Aging Effects

In reviewing LRA Section 3.3, the staff identified areas in which it needed additional information

to complete its review. Therefore, by letter to the applicant dated March 3, 2004, the staff

issued RAls concerning the specific issues to determine whether the applicant had

demonstrated that it will adequately manage the effects of aging for the FP system during the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The following paragraphs

describe the staff's RAls and the applicant's responses.

RAI 3.3.1-1

In RAI 3.3.1-1 (1), the staff inquiry concerned LRA Table 3.3.1, uAuxiliary Systems," item 3.3.1-

18. The staff asked the applicant to verify that all FP underground piping and fittings are

included in this item and have an AMP consistent with the GALL Report.

In its response, dated June 30, 2004, the applicant stated that this item does not include

underground fire water system piping and fittings.' The applicant provided AMR results for the

fire water system, including the extent of consistency with the GALL Report, in LRA Table

3.3.2-7. Table 3.3.2-7 of the LRA indicates components that are compared with the items of

LRA Table 3.3.1 by an entry in the "Table 1 Item" column. The applicant will manage the loss

of material in buried fire water system piping and components through the Fire Water System

Program, which, with enhancements, will be consistent with, but include exceptions to GALL

AMP XL.M27.

Based on its review, the staff finds the applicant's response to RAI 3.3.1 -1 (1) acceptable

because, although the cited item does not include underground FP piping and fittings, the

applicant showed that another item includes them in their entirety.

In RAI 3.3.1-1(2), the staff requested further explanation of LRA Table 3.3.1, item 3.3.1-19.

The staff asked the applicant to verify if this item includes any dry sprinkler systems and to

provide an AMP consistent with the GALL Report.

In its response, dated June 30, 2004, the applicant stated that it did not include dry sprinkler

systems in this item. The applicant provided AMR results for the FP system, including the

extent of consistency with the GALL Report, in LRA Table 3.3.2-7. An entry in the MTable 1

Item" column of LRA Table 3.3.2-7 indicates components included in Table 3.3.1. Item 3.3.1-5

of LRA Table 3.3.1 includes fire water piping with an internal air environment (i.e., dry sprinkler

piping). The applicant will manage loss of material in dry sprinkler piping and componentsthrough the Fire Water System Program, which, with enhancements, will be consistent with, but

include exceptions to GALL AMP XL.M27. (The applicant discussed the Fire Water System

Program enhancements and exceptions to GALL AMP XL.M27 in LRA Section B.1.11.2.) In

LRA Table 3.3.2-7, aluminum and copper alloy dry pipe sprinkler heads identified as component

type "spray nozzles" that are exposed to air internally and externally have no aging effects

because of the inherent corrosion resistance of these materials in air.

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Based on its review, the staff finds the applicant's response to RAI 3.3.1-1(2) acceptable

because the applicant verified that it did not include dry sprinkler heads within the cited item.

In RAI 3.3.1-1 (3), the staff requested further analysis of LRA Table 3.3.1, item 3.3.1-21. The

staff notified the applicant that GALL AMP XI.M27 does not omit review of aging effects for

treated water systems. Many of the aging effects/mechanisms listed are likely to occur even if

raw water is not the primary source. The staff asked the applicant to clarify the discussion

points for this item.

In its response, dated June 30, 2004, the applicant stated that item 3.3.1-21 of LRA Table 3.3.1

compares the alignment of the CNP AMR results with those in Table 3 (page 23) of the GALL

Report. These items refer to items VII.G.6a and VII.G.6b in the GALL Report (page VII.G.5),

which apply to water-based FP system components containing raw water. The CNP fire water

system uses treated water rather than raw water. Although item 3.3.1-21 in LRA Table 3.3.1

does not apply to CNP, fire water system components with an internal treated water

environment are subject to an AMR. Table 3.3.2-7 of the LRA lists aging effects and applicable

AMPs for the fire water system components requiring aging management.

Based on its review, the staff finds the applicant's response to RAI 3.3.1-1(3) acceptable

because further evaluation shows that GALL AMP XL.M27 is specific for raw water. Table

3.3.2-7 of the LRA contains the components of concern for treated water throughout.

In RAI 3.3.1-1 (4), the staff requested further explanation of LRA Table 3.3.2-7, "Fire Protection

Systems-General." Notes F, G, H, I, J, and 3 all dictate that the GALL Report does not cover

a portion of the item, but the applicant proposed no means of aging management evaluation.

The staff asked the applicant to describe the intended AMP.

In its response, dated June 30, 2004, the applicant stated that as described in item 9 on LRA

page 3.0-5, the notes in Table 3.3.2-7 describe the degree of consistency with the line items in

the GALL Report and do not exclude components from AMR. The "Aging Management

Programs" column of Table 3.3.2-7 identifies the aging effects of individual components and the

associated AMPs.

Based on its review, the staff finds the applicant's response to RAI 3.3.1-1 (4) acceptable

because, although the note refers to a specific variant of the component, the note is not

intended to exclude the component from the AMP identified.

In RAI 3.3.1-1 (5), the staff requested further analysis of LRA Table 3.3.2-7. The applicant did

not specifically list hose valve stations under any item in the summary of aging management.

The staff asked the applicant to identify an item which covers all hose valve stations and verify

compliance with GALL AMP XL.M27.

In its response, dated June 30, 2004, the applicant stated that as indicated on license renewal

drawings LRA-1 -5152B and LRA-2-5152C, hose valve stations comprise valves, piping, and

fittings. The component types "fittings," "piping," and "valve" identified in LRA Table 3.3.2-7

include the components of hose valve stations subject to an AMR. The Fire Protection Program

manages aging effects associated with the treated water internal environment for the

component types "fittings," "piping," and "valve" identified in LRA Table 3.3.2-7. As described in

LRA Section B.1.11.2, the Fire Water System Program, with enhancements, will be consistent

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with but include exceptions to GALL AMP XI.M27. Section B.1.1 1.2 of the LRA describes and

justifies those exceptions.

Based on its review, the staff finds the applicant's response to RAI 3.3.1-1(5) acceptable

because the applicant explained that the considered items include hose valve stations,

designated by the separate parts of the valve.

RAI 3.3.1-2

In RAI 3.3.1-2(1), the staff requested more information about LRA drawings LRA-1-5151A,

LRA-2-5151 A, LRA-1 -5151 C, and LRA-2-5151 C. At location L-5, a 1.5-inch vent line is present

from the diesel fuel oil day tank through a flame arrester to the room. These drawings do not

show the vent line and the flame arrester as subject to an AMR. However, it appears that the

intended function of the flame arrester is to ensure that vented gas will not lead to a fire. This

intended function is in accordance with 10 CFR 54.4(a)(3). The staff asked the applicant tojustify the exclusion of the flame arrester and vent line from the scope of license renewal and

from an AMR in accordance with the requirements of 10 CFR 54.4(a)(3) and

10 CFR 54.21 (a)(1).

In its response, dated June 30, 2004, the applicant stated that the flame arrester was

conservatively installed on the diesel fuel oil tank vent line but has no required intended

function. It is not required to support operation of the diesel engines and performs no function

that demonstrates compliance with the Commission's regulations for FP or other regulated

events. The flashpoint for diesel fuel is sufficiently high that NFPA Standard 30 does not

require a flame arrester, nor does the flame arrester have any function under 10 CFR 50.48.

Based on its review, the staff finds the applicant's response to RAI 3.3.1-2(1) acceptable

because the flame arrester is a nonrequired element providing additional safety.

In RAI 3.3.1-2(2), the staff requested more information about LRA drawing LRA-1-5151A,

LRA-2-5151A, LRA-1-5151C, and LRA-2-5151C. The drawings show a 2-inch overflow line at

location L6 as excluded from an AMR. The staff asked the applicant to justify the exclusion of

this overflow line from within the scope of license renewal and subject to an AMR in accordance

with the requirements of 10 CFR 54.4(a)(3) and 10 CFR 54.21(a)(1).

In its response, dated June 30, 2004, the applicant stated that the overflow line directs fuel oil

to a sump if the tank is overfilled. The vent line, flame arrester, and overflow line on the diesel

fuel oil day tank are not safety related and do not perform a pressure boundary function since

they are located above the fuel oil level in the tank and their failure would have no impact on the

ability of an EDG to perform its intended functions. Therefore, the vent line, flame arrester, and

overflow line on the diesel fuel oil day tanks do not have a license renewal intended function

and are not subject to an AMR based on the criteria of 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3).

Based on its review, the staff finds the applicant's response to RAI 3.3.1-2(2) acceptable

because the overflow line does not have a license renewal intended function.

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Aging Management Programs

The staff reviewed Table 3.3.2-7 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the FP system component groups.

For stainless steel exposed to air, the applicant identified no AERMs. The component types affected are bolting (ambient air) and flex hose (ambient and internal). Because the applicant did not identify an AERMs, and this is consistent with industry experience, the staff finds the

absence of an AMP for stainless steel components exposed to ambient air to be acceptable.

For copper alloy fittings, piping, spray nozzles, tubing, and valve component types exposed to

ambient air, as well as filter housing, fittings, spray nozzles, and valve component types internally exposed to air, the applicant identified no aging effect. Because the applicant did not

identify any AERMs, and this is consistent with industry experience, the staff finds the absence

of an AMP for copper alloy components exposed to ambient air to be acceptable.

In the LRA, the applicant stated that it manages the loss of material from carbon steel FP

components exposed to treated water using the Fire Protection Program (CNP.AMP B.1.1 1). Sections 3.0.3.2.5 and 3.0.3.2.6 of this SER, respectively, document the staff evaluation of this

program. The program addresses fittings, flange, heat exchanger bonnet and shell, heater housing, orifice, piping, pump casing, spray nozzles, tank, and tubing component types. This is

acceptable to the staff.

In the LRA, the applicant stated that loss of material from copper-alloy fittings, piping, tubing, and valve component types is managed using the Diesel Fuel Monitoring Program (CNP AMP

B.1.10). The staff documents its evaluation of this program in Section 3.0.3.2.4 of this SER.

On the basis that the Diesel Fuel Program maintains oil systems free of contaminants (primarily water and particles) and provides additives to mitigate aging effects, the staff finds that this

program adequately manages fouling and the loss of material for components exposed to fuel

oil.

In the LRA, the applicant stated that it manages the loss of material from copper alloy FP

components exposed to treated water using the Fire Protection Program (CNP AMP B.1.1 1), which is subdivided into the Fire Protection (CNP AMP B.1.1 1.1) and Fire Water System (CNP AMP B.1.11.2) Programs. The staff documents its evaluation of the Fire Protection Program in

Sections 3.0.3.2.5 and 3.0.3.2.6 of this SER, respectively. The program addresses fittings, heat exchanger tubes, spray nozzles, tubing, and valve component types. On the basis that the

program includes the SCs that credit this plant-specific program, the staff finds this to be

acceptable.

In the LRA, the applicant stated that it manages the loss of material from cast iron heat

exchanger shell, copper alloy heat exchanger tubes, carbon steel piping, and pump casing component types exposed to lubricating oil using the Oil Analysis Program (CNP AMP.1.23). The staff evaluation of this program is documented in Section 3.0.3.3.8 of this SER. On the

basis that the Oil Analysis Program maintains oil systems free of contaminants (primarily water

and particles), the staff finds that this program adequately manages fouling and the loss of

material for components exposed to lubricating oil.

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In the LRA, the applicant stated that it manages the loss of material due to wear of copper-alloy.

heat exchanger tubes exposed to both lube oil and treated water using the Fire Protection

Program. On the basis that the program includes the SCs that credit this plant-specific

program, the' staff finds this to be acceptable.

In the LRA, the applicant stated that it manages the loss of material from a carbon steel spray

nozzle exposed to air internally using the System Walkdown Prograrmi (CNP AMP B.1.38). The

staff evaluation of this program is documented in Section 3.0.3.3.14 of this SER. During the

AMP audit at the applicant's offices, the staff asked how internal loss of material would be

detected; iThe applicant's technical staff exlained that loss of carbon steel material sufficient

to challenge the intended function of the spray nozzle would be expected to produce indications

that would be evident on inspection without disassembly. This is acceptable to the staff on the

basis that (1) this plant-specific program provides for the management of loss of material for

this component, (2) evidence of significant internal loss of material will be visible to those

conducting system walkdowns, and (3) those conducting the walkdowns are guided by training

and procedure to monitor this aging effect.

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 FP system

components that are identified in this section. 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 provides an adequate description of the AMPs credited for,

managing aging in these components, as required by 10 CFR 54.21 (d).

3.3.2.3.8 Emergency Diesel Generator

Staff Evaluation

The staff reviewed the AMR of the EDG system component, material, environment, and AERM

combinations that are identified in the sections below titled 'Aging Effects" and "Aging

Management Programs." The applicant identified these combinations in LRA Table 3.3.2-8.'

For the combinations, the staff verified 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 are adequate.

Aging Effects

Table 2.3.3-8 of the LRA lists individual system components that are within the scope of license

renewal and are subject to an AMR. The component types evaluated in this section' include

bolting, compressor, expansion joints, filter housing, fittings, flex hoses, heat exchanger (shell),

heat exchanger (tubes),' heater housing, level glass gauge, manifold (piping), orifices, piping,

pneumatic cylinder, pump casing, sight flow iridicator, strainers,-tanks, thermowells, tubing, and

valves.

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For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel exposed to an internal air environmen t is subject to loss of material and

loss of material-wear. Carbon steel exposed to an internal exhaust air environment is

subject to cracking-fatigue. Carbon steel exposed to an internal lube oil or treated water

is subject to loss of material. Carbon steel bolts exposed to external air are subject to

loss of mechanical closure integrity.

* Stainless steel exposed to an internal treated water environment is subject to cracking.

Stainless steel bolts exposed to external air are subject to loss of mechanical closure

integrity.

Copper alloy exposed to an external air or lube oil environment is subject to fouling.

Copper alloy exposed to an internal treated water environment is subject to fouling.

Copper alloy exposed to a lube oil, external air, or treated water environment is subject

to loss of material-wear.

* Glass exposed to air or treated water experiences no aging effects.

Section 3.3.2.3.12 of this SER contains the staff's evaluation of loss of preload and cracking for

closure bolting.

During its review, the staff determined that it needed additional information to complete its

evaluation.

In Tables 3.3.2-1 through Table 3.3.2-11 for the auxiliary systems, the applicant listed several

components having environments and applicable aging effects with associated AMPs. In the

same columns, for the same component, material, and environment, the applicant listed no

aging effects and no AMPs. For example, in Table 3.3.2-11, page 3.3-130, the applicant

identified stainless steel bolting with a function of pressure boundary exposed to an external

environment of air as experiencing the loss of material, which is managed by the Bolting and

Torquing Activities Program. The same item in the table on page 3.3-130 for the same

component exposed to the same environment has no identified aging effects and therefore

requires no AMP. In addition, in Table 3.3.2-6, page 3.3-77, copper alloy valves exposed to an

external condensation environment experience the loss of material. The same item in the table

on page 3.3-77 for the same component exposed to the same environment has no identified

aging effects and therefore requires no AMP.

RAI 3.3.2-1

In RAI 3.3.2-1, the staff asked the applicant to explain these contradictory entries in the LRA

tables. By letter dated June 8, 2004, the applicant provided the following response applicable

to the EDG for RAI 3.3.2-1:

In LRA Tables 3.3.2-1 through 3.3.2-11 for the auxiliary systems, there are six

instances in which a component type lists both an aging effect and "none" for the

same material/environment combination. While this appears contradictory where

occurring, it is not because each component type in the table actually represents

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more than one component in the system. While the components are exposed to

the same overall environment, specific conditions for individual components

differ. The following paragraphs provide additional information for the instances

applicable to the EDG:

LRA Table 3.3.2-8, Emergency Diesel Generator (Page 3.3-95) - stainless

steel bolting exposed to air externally

Stainless steel bolting in this system is exposed to air and to significant

*vibration and/or elevated temperatures from the diesel engines. Therefore,-

loss of mechanical integrity (loss of pre-load) was identified as an aging

effect requiring management for this stainless steel bolting exposed to air.

-Stainless steel bolting in parts of the emergency diesel generator system that

are isolated from diesel engine vibration (e.g., air start subsystem) is

exposed to air, but is not exposed to significant vibration or elevated

temperatures from a diesel engine. Therefore, no aging effects requiring

management were identified for this stainless steel bolting exposed to air.

Based on its review, the staff finds the applicant's response to RAI 3.3.2-1 acceptable because

each component type in the table actually represents more than one component in the system,

and while the components are exposed to the same overall environment, specific conditions for

individual components differ as discussed by the applicant. Therefore, the staff's concerns

described in RAI 3.3.2-1 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 RAI, the staff finds that the aging effects of

the above EDG system 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 above components in the EDG system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above component

types, 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.

Table 3.3.2-8 of the LRA identifies the following AMPs for managing the aging effects described

above for the EDG system:

* Bolting and Torquing Activities Program

* Preventive Maintenance Program

* TLAA-Metal Fatigue Program -

* Oil Analysis Program

* Water Chemistry Control Program

* Heat Exchanger Monitoring Program

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The staff's detailed review of these AMPs appears in Sections 3.0.3.3.2, 3.0.3.3.10, 4.3, 3.0.3.3.8, 3.0.3.3.16, and 3.0.3.3.5 of this SER, respectively.

During its review, the staff determined that it needed additional information to complete its

evaluation.

For several stainless steel components listed in LRA Table 3.3.2-8, pages 3.3-95 to 3.3-112, the applicant identified cracking as an AERM for stainless steel with an internal treated water

environment. The applicant credited the Preventive Maintenance Program (CNP AMP B.1.25),

on page B-82 of the LRA, with managing the cracking aging effect by general inspections rather

than specific component-by-component listings. The program description states that the AMP

will manage the loss of material, cracking, fouling, and change in material properties for EDG

subsystem components. The GALL Report recommends management of these aging effects

using chemistry control programs supplemented by one-time inspections in low-flow areas.

RAI 3.3.2.1.8-1

In RAI 3.3.2.1.8-1, the staff asked the applicant to justify the effectiveness of the Preventive

Maintenance Program in managing the aging effect of cracking for each stainless steel

component so identified in Table 3.3.2-8 or to revise Table 3.3.2-8 to include an applicable chemistry control program and one-time inspection.

By letter dated June 8, 2004, the applicant stated the following:

Both the Preventive Maintenance Program, B.1.25, and the Chemistry One-Time

Inspection Program, B.1.41, would be effective in managing the aging effect of

cracking for stainless steel components subject to an internal treated water

environment. The Preventive Maintenance Program is credited for managing cracking of stainless steel components containing treated water, because a

representative sample of these components is inspected on a routine basis.

These inspections would reveal evidence of cracking such that corrective actions

can be taken to manage applicable aging effects. Degraded conditions or

adverse trends identified during inspections are addressed through the corrective

action process. In addition, the treated water environment of the EDG

subsystems is included in the Auxiliary Systems Water Chemistry Control

Program. Verification of the effectiveness of the chemistry control programs, by the Chemistry One-Time Inspection Program, will provide additional assurance

that aging effects, such as cracking, are effectively managed.

Based on its review, the staff finds the applicant's response to RAI 3.3.2.1.8-1 acceptable, because the applicant's response clarifies that it will use the appropriate AMPs recommended

by the GALL Report to detect and manage cracking in the stainless steel components. The

response resolves the initial concerns related to using the single AMP, the Preventive

Maintenance Program, as cited in Table 3.2.2-8. Therefore, the staff's concerns described in

RAI 3.3.2.1.8-1 are resolved.

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RAI 3.3.2.1.8-2

Table 3.3.2-8 of the LRA (pages 3.3-95 to 3.3-112) identifies several carbon steel components

in a treated water environment using a water chemistry control program to manage a loss .of.

material aging effect. The GALL Report also supports using a water chemistry program for

managing the loss of material to carbon steel. In RAI 3.3.2.1.8-2, the staff asked the applicant

to justify not including an AMP to manage the water chemistry of the treated water environment

for the carbon steel sight flow indicator (Table 3.3.2-8, page 3.3-106). -

By letter dated June 8, 2004, the applicant stated that, consistent with other carbon steel

components containing treated water as identified in LRA Table 3.3.2-8, the Water Chemistry

Control Program manages the loss of material of the carbon steel sight flow indicator. The -

applicant inadverten tly omitted the Water Chemistry Control Program from the component type;

"sight flow indicator," in LRA Table 3.3.2-8. Based on its review, the staff finds the applicant's

response to RAI 3.3.2.1.8-2 acceptable, because the applicant has provided an acceptable

explanation (clerical error), as requested; therefore, the staff's concern described in RAI

3.3.2.1.8-2 is resolved.

For stainless steel exposed to air, the applicant identified no AERMs. The component types

exposed to ambient air are bolting, fittings, flex hose, piping, strainer, thermowell, tubing, and

valves, and those .exposed to air internally are fittings, flex hose, piping, strainer, tubing, and

valves. Because the applicant did not identify an AERMs, and this is consistent with industry

experience, the staff finds the absence of a program for stainless steel components exposed to

ambient air to be acceptable.

In the LRA, the applicant stated that it will use the Oil Analysis Program (CNP AMP B.1.23) to

manage the loss of material from carbon steel filter housing, fittings, heat exchanger shell,

heater hiousing, piping, pump casing, strainer, tank, and valve. The staff evaluation of this

program appears in Section 3.0.3.3.8 of this SER. Because the Oil Analysis Program maintains

oil systems free of contaminants (primarily water and particles), the staff finds that this program

adequately manages loss of material for components exposed to lubricating oil.

For copper alloy filter housings, fittings, manifold, pneumatic cylinder, tubing, and valve

component types exposed to ambient or internal air, the applicant identified no aging effects.

Because the applicant did not identify any AERMs, and this is consistent with industry

experience, the staff finds the absence of a program for copper alloy components exposed to

ambient air to be acceptable.

In the LRA, the applicant stated that it will use the Water Chemistry Control Program (CNP

AMP B.1.40) to manage the loss of material from carbon steel fittings, heat exchanger shell,

heater housing, manifold, orifice, piping, pump casing, strainer, tank, thermowell, and tubing

component types in treated water. The staff evaluation of this program appears in Sections

3.0.3.2.15,3.0.3.2.16, and 3.0.3.3.16 of this SER. Because this approach is consistent with the

management of similar items identified in the GALL Report, the staff finds it to be acceptable.",,-

In the LRA, the applicant stated that it will manage the loss of material from carbon steel valve

component types by using both the Water Chemistry Control Program and the plant-specific

Preventive Maintenance, Program (CNP AMP B.1.25). The staff evaluation of this program

appears in Secti6n 3.0.3.3.10 of this SER. Because the use of the Water Chemistry Control

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Program is consistent with the management of similar items identified in the GALL Report, the

staff finds that its use to supplement the Preventive Maintenance Program is acceptable.

In the LRA, the applicant stated that it will manage the loss of material from copper-alloy

fittings, manifold, tubing, and valve component types by using the Diesel Fuel Monitoring

Program (CNP AMP B.1.10). The staff evaluation of this program appears in Section 3.0.3.2.4

of this SER. Because the Diesel Fuel Monitoring Program maintains oil systems free of

contaminants (primarily water and particles) and provides additives to mitigate aging effects, the

staff finds that this program adequately manages fouling and the loss of material for

components exposed to fuel oil.

In the LRA, the applicant stated that it will manage loss of material from copper alloy fittings,

heat exchanger tubes, tubing, and valve component types exposed to lube oil by using the Oil

Analysis Program (CNP AMP B.1.23). The staff evaluation of this program appears in Section

3.0.3.3.8 of this SER. Because the Oil Analysis Program maintains oil systems free of

contaminants (primarily water and particles), the staff finds that this program adequately

manages cracking and the loss of material for components exposed to lubricating oil.

In the LRA, the applicant stated that it will manage the loss of material from copper alloy fittings

and heat exchanger tubes in raw water by using the Service Water System Reliability Program

(CNP AMP B.1.29). The applicant will also use this program to manage fouling of heat

exchanger tubes. The staff evaluation of the Service Water System Reliability Program

appears in Section 3.0.3.2.11 of this SER. Because the use of this program is consistent with

the management of similar items identified in the GALL Report, the staff finds that its use to

supplement the Preventive Maintenance Program is acceptable.

In the LRA, the applicant stated that it will manage the loss of material from copper alloy fittings,

heat exchanger tubes, tubing, and valve component types in treated water by using the Water

Chemistry Control Program. Because this approach is consistent with the management of

similar combinations of material and environment identified in the GALL Report, the staff finds

this to be acceptable.

In the LRA, the applicant stated that it will manage loss of material from stainless steel fittings,

piping, strainer, tubing, and valve component types by using the Diesel Fuel Monitoring

Program (CNP AMP B.1.10). The staff documents its evaluation of this program in Section

3.0.3.2.4 of this SER. Because the Diesel Fuel Monitoring Program maintains oil systems free

of contaminants (primarily water and particles) and provides additives to mitigate aging effects,

the staff finds that this program adequately manages fouling and loss of material for

components exposed to fuel oil.

In the LRA, the applicant stated that it will manage cracking of stainless steel fittings, piping,

strainer, thermowell, and tubing component types exposed to lube oil by using the Oil Analysis

Program (CNP AMP B.1.23). The staff documents its evaluation of this program in Section

3.0.3.3.8 of this SER. Because the Oil Analysis Program maintains oil systems free of

contaminants (primarily water and particles), the staff finds that this program adequately

manages loss of material for components exposed to lubricating oil.

In the LRA, the applicant stated that it will manage the loss of material from stainless steel

fittings, piping, strainer, thermowell, tubing, and valve component types in lube oil by using the

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Oil Analysis Program (CNP AMP B.1.23). The staff documents its -evaluation of this program in

Section 3.0.3.3.8 of this SER. Because the Oil Analysis'Prograrm maintains oil systems free of

contaminants (primarily water and particles), the staff finds that this program adequately

manages loss of material for components exposed to lubricating oil.

In the LRA, the applicant stated that it will manage loss of material from stainless steel fittings,

piping,-strainer, thermowell, tubing, and valve component types in-treated water by using theWater Chemistry Control Program. The staff documents its evaluation of this program in

Sections 3.0.3.2.15, 3.0.3.2.16, and 3.0.3.3.16 of this SER. Because this approach is'

consistent with the management of similar items identified in the GALL Report, the staff finds it

to be acceptable.

In the LRA, the applicant stated that it will manage cracking and changes in material properties

for elastomers in flex hose by using the Preventive Maintenance Program (CNP AMP B.1.25).

The staff documents its evaluation of this program in Section 3.0.3.3.10 of this SER. The staff

could not identify how the applicant would monitor changes in material properties. Therefore,

the staff requested the applicant to clarify the method(s) used to monitor change in material

properties of elastomers in the flex hose associated with the EDG. Material properties that

could affect the performance of elastomers (e.g., hardness, flexibility) are not directly

measured.

RAI 3.3.3-2

By letter dated August 20, 2004, in RAI 3.3.3-2, the staff asked the applicant to provide a basis

for concluding that it will identify degradation of the elastomers before the intended function is

compromised, or to provide a technical basis for the conclusion that the elastomers in question

are not subject to these aging effects.

In its response dated September 2, 2004, the applicant stated that it-will verify the flexibility of

the hoses through physical manipulation of the' hose during the visual inspection, thereby

enhancing the inspector's ability to sense (both' visually and through 'touch) a change in material

properties that could affect the performance of the elastomers. The applicant stated that the

Preventive Maintenance Program will use appropriate examination methods to ensure that

degradation of flexible hoses in the EDG system will be identified before the intended function is

compromised.

On the basis of its review of the applicant's response to RAI 3.3.3-2, the staff finds that the

applicant has demonstrated that it will adequately manage change in material properties-of

flexible hoses resulting'from hardening and flexibility in the EDG system so that the'intended

function will be maintained consistent-with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

In the LRA, the applicant stated that it will 'manage fouling of copper-alloy heat exchanger tubes

in treated water by using the CNP Water Chemistry Control Program. Because this approach is

consistent with the management of similar items identified in the GALL Report, the staff finds it

to be acceptable.

In the LRA, the applicant stated that there-are no'aging effects for the level glass gauge

component type (glass) in an external environment of air or an internal environment of treated

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L

water. The GALL Report does not discuss similar component, material, and environment

combinations. On the basis that these components have no AERMs, the staff finds the

absence of an AMP for glass to be acceptable.

On the basis of its review of the information provided in the LRA and the additional information

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 EDG system component types that are

addressed in this section. 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 EDG system

components that are identified in this section. 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).

3.3.2.3.9 Security Diesel

Staff Evaluation

The staff reviewed the AMR of the security diesel system component, material, environment,

and AERM combinations that are identified in the sections below titled "Aging Effects" and

"Aging Management Programs." The applicant identified these combinations in LRA Table

3.3.2-9. For the combinations, the staff verified 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 they adequately describe the

programs.

Aging Effects

Table 2.3.3-9 of the LRA lists individual system components that are within the scope of license

renewal and are subject to AMR. The component types evaluated in this section include

bolting, compressor casing, expansion joints, filter housing, fittings, flanges, flex hoses, heat

exchanger (shell), heat exchanger (tubes), heater housing, piping, pump casing, silencer,

strainers, strainer housing, tanks, thermowells, tubing, and valves.

For these component types, the applicant identified the following materials, environments, and

AERMs:

Carbon steel exposed to an external air environment is subject to loss of mechanical

closure integrity. Carbon steel exposed to external air and internal exhaust gas environments is subject to loss of material and cracking-fatigue.

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* Stainless steel exposed to an external air environment is subject to loss of mechanical

closure integrity. Stainless steel exposed to an internal fuel oil environment is subject to

cracking. Stainless steel exposed to an external soil environment is subject to loss of

material.

* Copper alloy exposed to an external environment of lube oil or treated water is subject

to fouling. Copper alloy exposed to an internal environment of treated water

experiences fouling. Copper alloy exposed to an external environment of lube oil or

treated water is subject to loss of material-wear.

* Elastomer exposed to an internal environment of fuel oil or treated water or an external

environment of air is subject to the aging effects of change in material properties and

cracking.

Section 3.3.2.3.12 provides the staff's evaluation of the loss of preload and cracking for closure

bolting;

On the basis of its review of the information provided in the LRA, the staff finds that the aging

effects of the above security diesel system 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 above components in the

security diesel system.

Aging Management Programs

After evaluating the applicant's identification of'aging effects for each of the above component

types, 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.

Table 3.3.2-9 of the LRA identifies the following AMPs for managing the aging' effects described

above for the security diesel system:

* Bolting and Torquing Activities Program

* TLAA-Metal Fatigue Program

* System Testing Program

* Diesel Fuel Monitoring Program

* Preventive Maintenance Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.2, 4.3, 3.0.3.3.13,

3.0.3.2.4, and 3.0.3.3.10 of this SER, respectively.

During its review, the staff determined that it needed additional information to complete its

evaluation.

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RAI 3.3.2.1.9-1

Table 3.3.2-9 of the LRA identifies loss of material as an aging effect of stainless steel fittings

and stainless steel/carbon steel piping in a soil environment (pages 3.3-115 and 3.3-120). The

applicant identified the System Testing Program (CNP AMP B.1.37), page B-1 14 of the LRA, as

the applicable AMP for managing these aging effects. However, this AMP does not define

fitting or pipe condition or approximate rate of degradation as recommended in GALL AMPs

XI.M28 or XLI.M34 for buried fittings/piping. In RAI 3.3.2.1.9-1, the staff asked the applicant

either to justify the exclusion of the buried piping/fitting condition assessment in CNP AMP

B.1.37 in accordance with the GALL Report, or to revise the AMP accordingly.

In its response to RAI 3.3.2.1.9-1, by letter dated June 8, 2004, the applicant stated that the

items referred to in LRA Table 3.3.2 9 are associated with the security diesel underground fuel

oil tank and associated underground piping and fittings. The security diesel underground fuel

oil tank and associated underground piping and fittings are periodically tested for leakage using

timed system pressure tests. The applicant would discover leakage above the acceptance

criteria or other degraded conditions in time to take corrective actions before loss of the system

intended functions.

Based on its review, the staff does not find the applicant's response to RAI 3.3.2.1.9-1

acceptable. The applicant's response indicates that its periodic leakage testing would discover

leakage above acceptance criteria or other degraded conditions in time to allow for corrective

actions before a loss of system intended function. Although leakage tests define the

underground piping systems' integrity at a snapshot in time, they may not reflect the piping and

associated components' actual condition and rate of degradation during the period of extended

operation. The applicant described an underground tank and piping inspection program (Buried

Piping Inspection Program (CNP AMP B.1.6), page B-31 of the LRA) that appears to provide

the necessary actions to quantify current piping condition and estimate a rate of degradation

over the period of operation for components such as the security diesel underground

components. The applicant needed to provide justification that leak rate test results reflect the

actual rate of degradation and current condition of underground piping and fittings as defined in

Table 3.3.2-9. The applicant needed to also justify not using an AMP similar to the Buried

Piping Inspection Program (CNP AMP B.1.6) to manage the aging effects associated with

buried carbon steel and stainless steel piping, tanks, and fittings defined in Table 3.3.2-9.

By letter dated October 18, 2004, the applicant states that the security diesel underground fuel

oil tank and associated underground piping and fittings referred to in LRA Table 3.3.2-9 will be

included in the Buried Piping Inspection Program described in LRA Section B.1.6. LRA

Sections 3.3.2.1.9 and 3.3.2.2.11, as well as, Table 3.3.1 and Table 3.3.2-9 will be revised

accordingly. The System Testing Program (CNP AMP B.1.37) will also be revised to reflect

these changes. Based on its review, the staff finds that the applicant's inclusion of the security

diesel underground fuel oil tank and associated underground piping and fittings in the Buried

Piping Inspection Program will adequately evaluate the leak rate and current degradation of the

underground piping and fittings. The staff finds the approach acceptable for managing the

aging effects to the security diesel underground fuel oil tank and associated underground piping

and fittings; therefore, the staff's concern described in RAI 3.3.2.1.9-1 is resolved.

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RAI 3.3.2.1.9-2

Table 3.3.2-9 of the LRA (page 3.3-117) identifies the Preventive Maintenance Program (CNP:

AMP B.1.25), page B-82 of the LRA, as managing the change in material properties and . cracking of flex hoses with an internal environment of fuel oil and treated water. The program

description states that it will manage these aging effects by visual inspection and replacement

as necessary. It is not apparent from the program description if internal and external surfaces

will be inspected. Because of different internal and external environmental conditions, external

examination may not indicate internal component condition. In RAI 3.3.2.1.9-2, the staff asked

the applicant to explain how the visual examination referred to in the Preventive Maintenance

Program will ensure management of internal aging effects of these components.- -

By letter dated June 8, 2004, the applicant stated that the Preventive Maintenance Program will

manage the aging effects of change in material properties and cracking of the security diesel

elastomer flex hoses exposed internally to fuel oil and treated water environments by

perforrming visual inspection of both internal and external surfaces of these flex hoses, or - replacing them, as appropriate. Based on its review, the staff finds the applicant's response to

RAI 3.3.2.1.9-2 acceptable because it clarifies the locations of intended visual inspections as

both internal and external surfaces of flex hoses. This response resolves the concern

expressed in RAI 3.3.2.1.9-2.

RAI 3.3.2.1.9-3

Table 3.3.2-9 of the LRA (page 3.3-118) identifies the System Testing Program (CNP AMP

B.1.37),-page B-114 of the LRA, as managing fouling of copper alloy heat exchanger tube:.

components. For the same environment, component, and material, Table 3.3.2-8 (page

3.3.1 01) identifies the CNP Oil Analysis and Water Chemistry Control Programs as managing

fouling and the loss of material. -In RAI 3.3.2.1.9-3, the staff asked the applicant to justify the

exclusion of the Water Chemistry Control and Oil Analysis Programs from management of the

security diesel heat exchanger tube heat transfer function in Table 3.3.2-9.

By letter dated June 8, 2004, the applicant stated that although not explicitly credited in ,LRA

Table 3.3.2 9 for managing fouling of the security diesel heat exchanger tubes, the Auxiliary.

Systems Water Chemistry Control Program includes the security diesel jacket cooling water

system, as described in LRA Section 6.1.40.3, and the Oil Analysis Program includes the

security diesel lube oil system, as described in LRA Section B.1.23. The applicant inadvertently

omitted these two programs from LRA Table 3.3.2-9. Additionally,duringsystemtesting,

engine. paramete'rssuch as jacket water temperature, are monitored to assure that the heat

exchangers are capable of removing heat loads. Therefore, monitoring performed by the

System Testing Program, in conjunction with the Water Chemistry Control and Oil Analysis - Programs, effectively manages fouling of the heat exchanger tubes. Based on its review, the

staff finds the applicant's response to RAI 3.3.2.1.9-3 acceptable, because the applicant has

provided an acceptable justification (clerical error) as requested; therefore, the staff's concerns

described in RAI 3.3.2.1.9-3 are resolved. -

RAI 3.3.2.1.9-4 -

Table 3.3.2-9 of the LRA (page 3.3-119) identifies the System Testing Program (CNP AMP

B.1.37), on page B-114 of the LRA, as managing loss of material of copper alloy heat

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exchanger tube components in a treated water external environment. For the same

environment, component, and material, Table 3.3.2-8, page 3.3-102, identifies the Heat

Exchanger Monitoring and Water Chemistry Control Programs as managing loss of material

and loss of material-wear. In RAI 3.3.2.1.9-4, the staff asked the applicant to justify the

exclusion of Water Chemistry Control and Heat Exchanger Monitoring Programs from

management of the security diesel heat exchanger tube pressure boundary function in Table

3.3.2-9.

In its response to RAI 3.3.2.1.9-4, by letter dated June 8, 2004, the applicant stated that the

security diesel is a nonseismic, nonsafety related system. Since a major component of the

Heat Exchanger Monitoring Program is monitoring the seismic qualification of heat exchangers,

this program is not credited for the nonseismic security diesel engine coolant heat exchangers

or lube oil coolers. The security diesel engine coolant heat exchanger shell internal surfaces

and tube external surfaces are exposed to treated water from the Lake Township water system.

The Water Chemistry Control Program does not include Lake Township water chemistry.

Consequently, neither the Heat Exchanger Monitoring Program nor the Water Chemistry

Control Program would be appropriate for managing loss of material in these heat exchanger

tubes. The security diesel engine lube oil cooler shell internal surfaces and tube external

surfaces are exposed to lube oil, which is monitored by the Oil Analysis Program, as described

in LRA Section B.1.23. The Oil Analysis Program detects and controls contaminants (primarily

water and particulates), thereby preserving an environment that is not conducive to corrosion,

cracking, or fouling. Presence of engine coolant in the lube oil would indicate degradation of

the lube oil cooler tubes. Additionally, during the periodic security diesel testing in accordance

with the System Testing Program, operating parameters, such as oil pressure and jacket water.

temperature, are monitored. Abnormal indications and failure to meet acceptance criteria would

result in corrective action. Therefore, since the Oil Analysis and System Testing Programs.

monitor the parameters that would indicate unacceptable aging effects, these programs are

adequate for managing the effects of aging on the security diesel heat exchangers.

Based on its review, the staff did not find the applicant's response to RAI 3.3.2.1.9-4

acceptable. In RAI 3.3.2.1.9-4, the staff asked the applicant to justify the exclusion of the

Water Chemistry Control and Heat Exchanger Monitoring Programs from management of aging

of the security diesel heat exchanger tube pressure boundary function in Table 3.3.2-9. In

addition, Table 3.3.2-9, page 119, defines the same material, environment, and aging effects

combination (loss of material of copper alloy heat exchanger tube) for the diesel coolant heat

exchanger and the diesel lube oil cooler heat exchanger. The security diesel engine coolant

heat exchanger shell internal surfaces and tube external surfaces are exposed to treated water.'

The internal tube surfaces of the lube oil cooler heat exchanger are also exposed to treated

water. The applicant's response defines different reasons for excluding the Water Chemistry

Control and Heat Exchanger Monitoring Programs from management of the loss of material of

a copper alloy in a treated water environment for each component.

The following text discusses separately the adequacy of the responses related to each heat

exchanger.

Diesel Coolant Jacket Water Heat Exchanger and Diesel Lube Oil Cooling Heat Exchanger.

The portion of the applicant's response to RAI 3.3.2.1.9-4 addressing these heat exchangers

states the following:

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Since a major component of the Heat Exchanger Monitoring Program will be

monitoring the seismic qualification of heat exchangers, this program is not

credited for the non-seismic security diesel engine coolant heat exchangers or

lube oil coolers.

The description of the applicant's Heat Exchanger Monitoring Program (CNP AMP B.1.13)

states the following:

The Heat Exchanger Monitoring Program will inspect heat exchangers for degradation

using nondestructive examinations, such as eddy current inspections or visual

inspections or, if appropriate, the heat exchanger will be replaced. If degradation is

found, an evaluation will be performed to determine its effects on the heat exchanger

design functions.

This statement, as well as the type of testing involved, indicates that CNP AMP B.1.13

manages several heat exchanger condition and functionality issues other than those affecting

seismic qualification concerns. Other CNP AMP B.1.13 text supports this interpretation, stating

the following:

The aging effects for the heat exchanger tubes that will be managed by this program

are loss of material and cracking. Eddy current inspection of the tubes will be

performed every 10 years or more frequently if inspection results indicate a need for

more frequent inspections.

This statement specifically addresses the AMP's purpose of managing the loss of material

aging effect. Based on the program description and use of this AMP to manage loss of material

in heat exchangers of the same material and environment, the applicant's justification for

omitting the Heat Exchanger Monitoring Program is unsatisfactory. The applicant needed to

provide further justification for omitting the Heat Exchanger Monitoring Program from the aging

management of security diesel heat exchangers.

The applicant's response states that the Water Chemistry Control Program is not appropriate

for managing the loss of material aging effect because Lake Township supplies the treated

water used for the diesel jacket water cooling heat exchanger. However, industry experience

has shown the importance of water chemistry control in managing loss of material in treated

water systems. The GALL Report requirements repeatedly define water chemistry control as

an important management technique to control the loss of material in a treated water

environment. The initial provider of the treated water source does not lessen the importance of

water chemistry control in managing loss of material. Operational tests as described in the

System Testing Program (CNP B.1.37) do not control or minimize the rate of degradation, nor

do functional tests detect changes in water chemistry that directly affect the rate of degradation.

In a follow-up to RAI 3.3.2.1.9-4, the staff asked the applicant to provide further justification for

not utilizing water chemistry control to manage the loss of material aging effect or to refer to an

applicable AMP that manages water chemistry of the security diesel heat exchangers.-

Security Diesel Lube Oil Cooling Heat Exchanger. The portion of the applicant's response to

RAI 3.3.2.1.9-4 addressing this heat exchanger indicates that monitoring of oil condition and

operational system testing provide adequate control and management of loss of material.

Unlike water chemistry control, oil condition testing and functional testing do not manage

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factors affecting the rate of degradation resulting from loss of material. In contrast, the AMPs

defined by the applicant control the level of component degradation below some quantifiable

level. Changes in heat exchanger performance or loss of tube integrity reflective of some

minimal level of degradation must occur before actions can be taken to restore heat exchanger

performance.

As indicated in RAI 3.3.2.1.9-4, the applicant uses the CNP Oil Analysis, Water Chemistry

Control, and Heat Exchanger Monitoring Programs to manage the aging of other lube oil heat

exchangers within the scope of license renewal. Use of the Water Chemistry Control Program

and Heat Exchanger Monitoring Program minimizes the rate of component degradation and

provides quantifiable data related to the actual internal condition of the heat exchanger. The

applicant's aging management of the security diesel lube oil heat exchanger does neither. The

staff asked the applicant to provide further justification for not using the Water Chemistry

Control Program and Heat Exchanger Monitoring Program to manage the security diesel lube

oil heat exchanger. The staff also asked the applicant to explain the differences in aging

management of security diesel heat exchangers and EDG heat exchangers.

The GALL Report uses two main programs to minimize degradation of heat exchanger

components in a treated water environment and maintain the pressure boundary function.

Water chemistry control minimizes the rate of degradation from loss of material. Visual

examination and nondestructive testing quantify the heat exchanger condition and verify the

adequacy of water chemistry control. The programs defined by the applicant to manage the

security diesel's heat exchanger components exposed to a treated water environment do not

minimize aging effects to the same degree nor provide the same level of assurance in

maintenance of the pressure boundary function. The applicant's AMPs detect the loss of

material aging effect only after heat exchanger degradation has resulted in loss of pressure

boundary integrity between the heat exchanger shell and tube sides or changes in heat transfer

properties. The applicant's response does not justify the omission of a Water Chemistry

Control Program or Heat Exchanger Monitoring Program from management of security diesel

heat exchangers. The staff requested that the applicant explain why the security diesel heat

exchanger's AMPs, as defined in Table 3.3.2-9, are as effective in managing of the loss of

material aging effect as those defined in the GALL Report.

By letter dated October 18, 2004, the applicant responded to the two follow-up requests by

expressing that the security diesel lube oil cooler is a shell and tube heat exchanger with lube

oil internal to the shell and engine coolant (treated water) in the tubes. LRA Table 3.3.2-9

indicates that water chemistry control manages the loss of material of copper alloy heat

exchanger (tubes) in a treated water internal environment. The line item in the table on page

3.3-119 of the LRA refers to the internal tube side of the security diesel lube oil cooler. The

applicable aging management program is the Water Chemistry Control-Auxiliary Systems

Water Chemistry Control Program (CNP AMP B.1.40.3).

The applicant also states that as indicated in LRA Tables 3.3-8 and 3.3-9 on pages 3.3-102 and

3.3-118, respectively, the Oil Analysis Program, is described in LRA Section B.1.23, manages

the loss of material of both the security diesel and EDG lube oil cooler tube external surfaces.

Therefore, water chemistry control does manage loss of material of the security diesel lube oil

cooler tube internal surfaces, and the Oil Analysis Program manages the security diesel and

EDG lube oil cooler tube external surfaces. To verify that aging effects are not occurring, the

Chemistry One-Time Inspection Program, which is described in LRA Section B.1.41, will be

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used to inspect the security diesel lube oil cooler tube internal surfaces. No applicable

comparison to the GALL Report exists for the' security diesel lube oil heat exchanger tubes

because the GALL Report does not evaluate these heat exchanger tubes or similar copper alloy

components in a treated water environment. Furthermore, a comparison between the security

diesel heat exchangers and EDG heat exchangers is not required, as the inclusion of the

security diesel heat exchangers in the Chemistry One-Time Inspection Program will provide the

necessary verification that loss of material of the heat exchanger tubes is not occurring. Based

on its review, the staff finds that the applicant clarified the differences in approach for managing

the internal and external surfaces of the heat exchanger and oil cooler tubes using the Water

Chemistry Control-Auxiliary Systems Water Chemistry Control and the Oil Analysis Programs.

By also including the Chemistry One-Time Inspection Program as an applicable AMP for these

components, the applicant further ensures the proper management of the identified aging

effect, loss of material. Therefore, the staff's concerns described in RAI 3.3.2.1.9-4 are

resolved.

RAI 3.3.2.1.9-5

Table 3.3.2-9 of the LRA (page 3.3-124) identifies the Preventive Maintenance Program (CNP

AMP B.1.25), page B-82 of the LRA, as managing the change in material properties and

cracking of flex hoses with an internal environment of fuel oil. The program description states

that it will manage these aging effects by visual inspection and replacement as necessary. It

does not indicate whether the applicant will inspect internal and external surfaces. Because of

different internal and external environmental conditions, the external condition may not' -

represent the internal component condition. In RAI 3.3.2.1.9-5, the staff asked the applicant to

explain how the visual examination referred to in the Preventive Maintenance Program will

ensure management of internal aging effects.

By letter dated June 8, 2004, the applicant stated that the elastomer tubing listed in LRA Table'

3.3.2-9 refers to plastic material used in the security diesel day tank level gauges. The internal

surface of the clear plastic gauge used for local indication is evident during visual inspections.

The internal surface of the plastic tubing used for remote indication is exposed to fuel oil and

air. The Preventive Maintenance Program will manage the aging effects of change in material

properties and cracking of this tubing by providing for visual inspection of both internal surfaces

(at the connection point) and external surfaces of the tubing, or its replacement, as appropriate.

Based on its review, the staff finds the applicant's response to RAI 3.3.2.1.9-5 acceptable,

because the response clarifies the component and material in question and explains the visual

examination capability related to internal surfaces. The response resolves the concerns related

to assessment of internal material condition and environmental differences; therefore, the

staff's concerns described in RAI 3.3.2.1.9-5 are resolved.

RAI 3.3.2.1.9-6

Table 3.3.2-9 of the LRA identifies the System Testing Program (CNP AMP B.1.37) as

managing the loss of material on the internal surface of the security diesel heat exchanger shell

in a treated water environment. The System Testing Program manages these aging effects by

periodically starting the security diesel and operating it in accordance with manufacturer's -

recommendations, while monitoring system flow and system pressure. -In RAI 3.3.2.1.9-6, the

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staff asked the applicant to describe how the System Testing Program manages aging effects

on the internal surfaces of the heat exchanger shell.

By letter dated June 8, 2004, the applicant responded by stating the following:

Testing of the security diesel generator is performed to demonstrate operability

of the security diesel and to demonstrate the security diesel fuel oil system's

ability to perform its intended functions. In addition to monitoring system flow,

pressure, and temperature, monitoring for abnormal conditions, such as leakage,

is also performed during the conduct of these system tests. Malfunctioning

equipment, leakage, or failure to meet acceptance criteria during system testing

would result in corrective action being taken. Loss of material on the treated

water side of the heat exchanger shell would be detected in the form of pinhole

leaks caused by isolated pitting or crevice corrosion. Monitoring for component

leakage and system operating parameters under the System Testing Program

provides assurance that loss of material from the internal surfaces of the heat

exchanger shell will be identified during testing, prior to resulting in loss of

function of the heat exchanger. This level of monitoring is commensurate with

the safety significance of this non-seismic, non-safety-related component.

Based on its review, the staff does not find the applicant's response to RAI 3.3.2.1.9-6

acceptable. The GALL Report recommends two programs to minimize the degradation of heat

exchanger components in a treated water environment and maintain the pressure boundary

function. Water chemistry control minimizes the rate of degradation from the loss of material.

Visual examination and nondestructive testing quantify the heat exchanger condition and verify

the adequacy of water chemistry control. The programs defined by the applicant to manage the

security diesel's heat exchanger shell exposed to a treated water environment do not minimize

aging effects to the same degree nor provide the same level of assurance in maintenance of

the pressure boundary function. The applicant's AMPs detect the loss of material aging effect

only after heat exchanger degradation has resulted in a detectable loss of pressure boundary

integrity or changes in heat transfer properties. The applicant's response does not justify the

omission of the Water Chemistry Control Program or Heat Exchanger Monitoring Program from

management of security diesel heat exchangers. The applicant needed to explain why the

security diesel heat exchanger's AMPs, as defined in Table 3.3.2-9, are as effective in

managing the loss of material aging effect as those defined in the GALL Report.

By letter dated October 18, 2004 the applicant stated the following:

The security diesel jacket water coolers are shell and tube heat exchangers with

engine coolant (treated water) internal to the tubes and Lake Township water

(treated water) internal to the shell. Loss of material of the tube internal surfaces

is managed by water chemistry control as indicated [on] Page 3.3-119 of LRA

Table 3.3.2-9. The applicable aging management program is the Auxiliary

Systems Water Chemistry Control Program, which is described in LRA Section

B.1 .40.3.

Because Lake Township water (shell internal and tube external environments)

chemistry is not controlled by CNP, a chemistry control program was not credited

in the LRA. However, Lake Township water is provided by a municipality that is

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a Michigan state-licensed public water supplier subject to provisions in the

Michigan Department of Environmental Quality (MDEQ) Safe Drinking Water Act

1976 PA 399, and Administrative Rules, as amended, which include compliance

with contaminant standards, and certification, monitoring, and reporting

requirements. Lake Township water is potable water that has been treated with

chemicals by the municipality. The municipality monitors contaminants such as

chlorides and fluorides to maintain the water quality within MDEQ and

Environmental Protection Agency regulations. Because the contaminant levels

are maintained to ensure compliance with standards, significant aging effects are

not expected. To verify the absence of significant aging effects, the Chemistry

One-Time Inspection Program will include inspection of the surfaces of the

security diesel jacket water coolers that are exposed to Lake Township water.

The periodicity of further inspections will be based on the condition of the coolers

in relation to their time-in-service. There is no applicable comparison to NUREG1801 for the security diesel jacket water coolers since neither these coolers, nor

any similar components, are evaluated by NUREG-1 801.

Based on its review, the staff finds that the water chemistry of the Lake Township water supply

has adequate controls to ensure its ability to prevent aging to the security diesel jacket water

coolers that are exposed to Lake Township water. The applicant has also revised the LRA to

include use of the Chemistry One-Time Inspection Program which will include inspection of the

surfaces of the security diesel jacket water coolers that are exposed to Lake Township water.

By also including the Chemistry One-Time Inspection Program as an applicable AMP for these

components, the applicant further ensures that the identified aging effect of loss of material will

be properly managed. Therefore, the staff's concern described in RAI 3.3.2.1.9-6 is resolved.

In the LRA, the applicant stated that it will manage the loss of material in carbon steel filter

housing, fittings, heat exchanger shell, piping, pump casing, strainer, strainer housing, tubing,

and valve component types using the Oil Analysis Program (CNP AMP B.1.23). -The staff

evaluation of this program appears in Section 3.0.3.3.8 of this SER. Because the Oil Analysis

Program maintains oil systems free of contaminants (primarily water and particulates), the staff

finds that this program adequately manages cracking and the loss of material for components

exposed to lubricating oil.

For copper alloy filter housing, fittings, heat exchanger (shell), pump casing, strainer housing,

and tubing component types exposed to ambient air, the applicant identified no aging effects.

Because the applicant did not identify any AERMs, and this is consistent with industry

experience, the staff finds the absence of an AMP for copper alloy components exposed to

ambient air to be acceptable.

In the LRA, the applicant stated that it will manage loss of material from copper-alloy filter

housing, fittings, pump casing, strainer housing, and tubing component types by using the

Diesel Fuel Monitoring Program (CNP AMP B.1.10). The staff evaluation of this program

appears in Section 3.0.3.2.4 of this SER. Because the Diesel Fuel Monitoring Program

maintains oil systems free of contaminants (primarily water and particles) and provides

additives to mitigate aging effects, the staff finds that this program adequately manages fouling

and the loss of material for components exposed to fuel oil. -

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I

In the LRA, the applicant stated that it will manage loss of material from carbon steel fittings,

heater housing, piping, pump casing, tank, thermowell, and tubing component types in treated

water by using the Water Chemistry Control Programs. The staff evaluation of the Water

Chemistry Control Programs appears in Sections 3.0.3.2.15, 3.0.3.2.16, and 3.0.3.3.16 of this

SER. Because this approach is consistent with the management of similar items identified in

the GALL Report, the staff finds it to be acceptable.

In the LRA, the applicant stated that it will manage loss of material from copper-alloy fittings in

contact with the soil by using the plant-specific System Testing Program (CNP AMP B.1.37).

The staff evaluation of this program appears in Section 3.0.3.3.13 of this SER. Because similar

aging effects occur for copper alloy materials in a soil environment and copper alloy materials in

an internal fuel oil environment, and the system testing program scope includes the

components of the security diesel system for this aging effect, the staff finds this to be

acceptable.

In the LRA, the applicant stated that it will also use the Water Chemistry Control Program to

manage loss of material from copper-alloy fittings, heat exchanger tubes, and tubing

component types in treated water. Because this approach is consistent with the management

of similar items identified in the GALL Report, the staff finds it to be acceptable.

For stainless steel exposed to ambient air, the applicant identified no AERMs. The component

types affected are fittings, flange, flex hose, piping, tubing, and valves. Because the applicant

did not identify any AERMs, and this is consistent with industry experience, the staff finds the

absence of an AMP for stainless steel components exposed to ambient air to be acceptable.

In the LRA, the applicant stated that it will manage loss of material from stainless steel fittings,

flange, flex hose, piping, strainer, tubing, and valve component types by using the Diesel Fuel

Monitoring Program (CNP AMP B.1.10). The staff evaluation of this program appears in

Section 3.0.3.2.4 of this SER. Because the Diesel Fuel Monitoring Program maintains oil

systems free of contaminants (primarily water and particles) and provides additives to 'mitigate

aging effects, the staff finds that this program adequately manages fouling and loss of material

for components exposed to fuel oil.

In the LRA, the applicant stated that it will manage cracking and changes in material properties

for elastomers in flexible hose and tubing exposed to the air by using the Preventive

Maintenance Program (CNP AMP B.1.25). The staff evaluation of this program appears in

Section 3.0.3.3.10 of this SER. The staff could not identify how the applicant would monitor

changes in material properties. The staff requested clarification of the method(s) used to

monitor a change in material properties of elastomers in the flex hose associated with the

security diesel. Material properties that could affect the performance of elastomers (e.g.,

hardness, flexibility) are not directly measured.

RAI 3.3.3-2

By letter dated August 20, 2004, in RAI 3.3.3-2, the staff asked the applicant to provide a basis

for concluding that it will identify degradation of the elastomers before the intended function is

compromised or to provide a technical basis for its conclusion that the elastomers in question

are not subject to these aging effects.

I

I

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In its response dated September 2, 2004, the applicant stated that it will verify the flexibility of

the hoses through physical manipulation of the hose during the visual inspection, thereby

enhancing the inspector's ability to sense (both visually and through touch) a change in' material

properties that could affect the performance of the elastomers. The applicant stated that the

Preventive Maintenance Program will use appropriate examination methods to ensure that

degradation of flexible hoses in the security diesel system will be identified before the intended

function is compromised.

On the basis of its review of the applicant's response to RAI 3.3.3-2, the staff finds that theapplicant has demonstrated that it will adequately manage change in material properties of

flexible hoses resulting from hardening and flexibility in the security diesel system so that the

intended function will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

In the LRA, the applicant stated that it will manage loss of material in copper alloy heat

exchanger tubes by using the Oil Analysis Program (CNP AMP B.1.23). The staff evaluation of

this program appears in Section 3.0.3.3.8 of this SER. Because the Oil Analysis Program

maintains oil systems free of contaminants (primarily water and particulates), the staff finds that

this program adequately manages cracking and the loss of material for components exposed to

lubricating oil.

On the basis of its review of the information provided in the LRA and supplemental information

provided by the applicant, the staff finds the applicant has identified appropriate AMPs for

managing the aging effects of the security diesel system component types that are addressed

in this section. 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 security diesel

system components identified in this section. 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).

3.3.2.3.10 Postaccident Containment Hydrogen Monitoring System

Staff Evaluation

The staff reviewed the AMR of the PACHMS component, material, environment, and AERM

combinations that are identified in the sections below titled "Aging Effects" and "Aging

Management Programs." The applicant identified these combinations in LRA Table 3.3.2-10.

For the combinations, the staff verified 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 they adequately describe the programs.

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I

Aging Effects

Table 2.3.3-10 of the LRA lists individual system components that are within the scope of

license renewal and are subject to AMR. The component types evaluated in this section

include analyzer body, bolting, filter, fittings, flex hoses, heat exchangers, moisture separator,

orifices, piping, pump casing, and valves.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Stainless steel exposed to an internal air environment experiences cracking-fatigue.

Stainless steel exposed to an internal oxygen environment experiences no aging effects.

* Carbon steel exposed to an internal oxygen environment experiences no aging effects.

* Elastomers exposed to an internal oxygen environment and external air environment are

subject to change in material properties and cracking.

* Brass exposed to an oxygen internal environment experiences no aging effects.

Section 3.3.2.3.12 presents the staff's evaluation of the loss of preload and cracking for closure

bolting.

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI 3.3.2-1

In LRA Tables 3.3.2-1 through Table 3.3.2-11 for the auxiliary systems, the applicant listed

several components having environments and applicable aging effects with associated AMPs.

In the same columns, for the same component, material, and environment, the applicant listed

no aging effects and no AMPs. For example, in Table 3.3.2-11, page 3.3-130, the applicant

identified stainless steel bolting with a function of pressure boundary exposed to an external

environment of air as experiencing loss of material managed by the Bolting and Torquing

Activities Program. The same item in the table on page 3.3-130 for the same component

exposed to the same environment has no identified aging effects and therefore requires no

AMP. In addition, in Table 3.3.2-6, page 3.3-77, copper alloy valves exposed to an external

condensation environment experience a loss of material. The same item in the table on page

3.3-77 for the same component exposed to the same environment has no identified aging

effects and therefore requires no AMP. In RAI 3.3.2-1, the staff asked the applicant to explain

these contradictory entries in the LRA tables.

By letter dated June 8, 2004, the applicant provided the following response to RAI 3.3.2-1

applicable to the PACHMS:

In LRA Tables 3.3.2-1 through 3.3.2-11 for the auxiliary systems, there are six

instances in which a component type lists both an aging effect and "none" for the

same material/environment combination. While this appears contradictory where

occurring, it is not because each component type in the table actually represents

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more than one component in the system. While the components are exposed to

the same overall environment, specific conditions for individual components

differ. The following paragraphs provide additional information for the instances

applicable to the post-accident containment hydrogen monitoring system:

LRA Table 3.3.2 10, Post-Accident Containment Hydrogen Monitoring

System (Page 3.3 127)-stainless steel heat exchangers exposed to air -

internally (heat transfer and pressure boundary intended functions)

-- Stainless steel heat exchangers exposed to air internally within the hydrogen

analyzer sample panel "hot box" are exposed to a temperature slightly above

the threshold for fatigue because they are heated by heat tracing. Therefore,

cracking due to fatigue was conservatively identified as an aging effect

requiring management for these stainless steel heat exchangers exposed to

air internally. Stainless steel heat exchangers exposed to air internally, but

outside the uhot box" are not exposed to temperatures above the threshold

for fatigue. Therefore, no aging effects requiring management were

identified for these stainless steel heat exchangers exposed to air internally.'

* iRA Table 3.3.2 10, Post-Accident Containment Hydrogen Monitoring

System (Page 3.3 129)-stainless steel valves exposed to air internally

Stainless steel valves exposed to air internally in the sample flow path are

exposed to a temperature slightly above the threshold for fatigue because

they are heated by heat tracing. Therefore, cracking due to fatigue was

conservatively identified as an aging effect requiring management for these

stainless steel valves exposed to air internally. Stainless steel valves

exposed to air internally in the reagent gas flow path are not exposed to

temperatures above the threshold for fatigue. Therefore, no aging effects

requiring management were identified for these stainless steel valves

exposed to air internally.

Based on its review, the staff finds the applicant's response to RAI 3.3.2-1 acceptable because

each component type in the table actually represents more than one component in the system,

and while the components are exposed to the same overall environment, specific conditions for

individual components differ as discussed by the applicant. Therefore, the staff's concerns

described in RAI 3.3.2-1 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 RAI, the staff finds that the aging effects of

the above PACHMS 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 above components of the PACHMS.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above component

types, the staff evaluated the AMPs to determine if they are appropriate for managing the

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identified aging effects. The staff also verified that the UFSAR Supplement adequately

describes the program.

Table 3.3.2-10 of the LRA identifies the following AMPs for managing the aging effects

described above for the PACHMS:

* TLAA-Metal Fatigue Program

* Preventive Maintenance Program

The staff's detailed review of these AMPs appears in Sections 4.3 and 3.0.3.3.10 of this SER,

respectively.

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI 3.3.2.1.10-1

In the LRA, Table 3.3.2-10 (page 3.3-127) identifies the Preventive Maintenance Program (CNP

AMP B.1.25), page B-82 of the LRA, as managing a change in material properties and cracking

of flex hoses with an internal environment of oxygen. The program description states that it will

manage these aging effects by visual inspection and replacement as necessary. It is not

apparent from the program description if internal and external surfaces will be inspected.

Because of different internal and external environmental conditions, external examination may

not indicate internal component conditions. In RAI 3.3.2.1.10-1, the staff asked the applicant to

explain how the visual examination referred to in the Preventive Maintenance Program will

ensure management of internal aging effects.

By letter dated June 8, 2004, the applicant replied as follows:

The flex hoses listed in LRA Table 3.3.2-10 are small rubber hoses on the

oxygen supply bottles. These bottles store pure oxygen, which is used as a

reagent for the hydrogen analyzers. The hoses are exposed to oxygen internally

and ambient air externally. Degradation of rubber from cracking and change in

material properties can be caused by ultraviolet radiation, ionizing radiation, or

thermal exposure. The internal hose surfaces are not exposed to ultraviolet

radiation, since they are not exposed to light. The supply bottles and hoses are

installed in a low radiation area. Therefore, the component dose will be

substantially lower than the radiation dose threshold for elastomers (1 06-1 7

Rad). Both internal and external hose surfaces are close to the ambient air

temperature of the auxiliary building. Since oxygen is also present in

atmospheric (ambient) air, both internal and external surfaces of the hoses are

exposed to oxygen. The external surface is exposed to an environment that is

more severe than the internal environment (ultraviolet radiation); neither the

internal nor external surfaces are exposed to elevated temperatures or high

radiation. Therefore, inspection of the external surfaces is adequate to ensure

detection of aging effects prior to loss of the pressure boundary intended

function.

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Based on its review, the staff does not find the applicant's response to RAI 3.3.2.1.10-1

acceptable. The applicant's response provides clarification as to the specific elastomer

components requiring aging management, as well as the associated environmental conditions

and preventive maintenance activities. The applicant's response indicates that external

environmental conditions are more severe than the internal environmental conditions for the

components of concern. Based on environmental conditions, the applicant indicated that visual

inspection of the external surface will successfully manage the associated aging of these

elastomer components and that inspection of the internal surface is not necessary. However,

aging of elastomer components is a complex issue. The materials' specific chemical

properties, as well as environmental conditions, affect the rate of aging. As the applicant's

response indicates, internal and external environmental conditions are different, but the

applicant's assumption that the material aging will occur more rapidly and be more apparent at,

the external surface has not been substantiated. A Sandia National Laboratory study titled,

"Prediction of Elastomer Lifetimes from Accelerated Thermal Aging Experiments," by Kenneth

T. Gillen and Roger L. Clough, indicates that oxygen concentration and pressure affect the

oxidation rate of elastomers. The applicant's response to RAI 3.3.2.1.10-1 does not provide

adequate information to substantiate aging management of these components by external

visual observation alone. The staff requests that the applicant substantiate the adequacy of

external surface visual examination in managing aging by providing details related to the

applicable components' inspection/failure/repair frequency experienced during the plant's

operating history.

By letter dated October 18, 2004, the applicant stated that a review of the operating experience

for these hoses did not identify any pressure boundary failures due to elastomer degradation.

However, prior to the period of extended operation, I&M will inspect internal hose ends and

external surfaces of the post-accident hydrogen monitoring system reagent supply rubber

hoses referred to in LRA Table 3.3.2-10. The periodicity of future inspections will be based on

the condition of the hoses in relation to their time in service. Based on its review, the staff finds

the applicant's assessment of operating history and conditions for verification and future

inspections acceptable for managing the aging effects to the hoses; therefore, the staff's

concern described in RAI 3.3.2.1.10-1 is resolved.

For stainless steel component types exposed to air, both ambient and internal, the applicant

identified no AERMs. The component types affected are analyzer body, bolting, filter, heat

exchanger, moisture separator, orifice, piping, pump casing, and valve. Because the applicant

did not identify any AERMs, and this is consistent with industry experience, the staff finds the

absence of a program for stainless steel components exposed to ambient air to be acceptable.

In the LRA, the applicant stated that it will manage cracking and changes in material properties

for elastomers in flexible hose by using the Preventive Maintenance Program (CNP AMP

B.1.25). The staff evaluation of this program appears in Section 3.0.3.3.10 of this SER.

The staff was unable to identify how the applicant would monitor changes in material properties.

The staff requested clarification of the method(s) used to monitor a change in material

properties of elastomers in the flex hose associated with the PACHMS. Material properties that

could affect the performance of elastomers (e.g.-, hardness, flexibility) are not directly

measured.

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RAI 3.3.3-2

By letter dated August 20, 2004, in RAI 3.3.3-2, the staff asked the applicant to provide a basis

for concluding that it will identify degradation of the elastomers before the intended function is

compromised, or to provide a technical basis for its conclusion that the elastomers in question

are not subject to these aging effects.

In its response dated September 2, 2004, the applicant stated that it will verify flexibility of the

hoses through physical manipulation of the hose during the visual inspection, thereby

enhancing the inspector's ability to sense (both visually and through touch) a change in material

properties that could affect the performance of the elastomers. The applicant stated that the

CNP Preventive Maintenance Program will use appropriate examination methods to ensure the

identification of degradation of flexible hoses in the PACHMS before the intended function is

compromised.

On the basis of its review of the applicant's response to RAI 3.3.3-2, the staff finds that the

applicant has demonstrated that it will adequately manage change in material properties of

flexible hoses resulting from hardening and flexibility in the PACHMS so that the intended

function will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

In the LRA, the applicant identified no aging effects for stainless steel piping and valves

exposed to an environment of hydrogen or nitrogen gas. Because the applicant did not identify

any AERMs, and this is consistent with industry experience, the staff finds the absence of an

AMP for stainless steel components exposed to ambient air to be acceptable.

For brass valves exposed to ambient air, the applicant identified no AERMs. Because the

applicant did not identify any AERMs, and this is consistent with industry experience, the staff

finds the absence of an AMP for brass valves exposed to ambient air to be acceptable.

On the basis of its review of the information provided in the LRA and the additional information

provided by the applicant's response to the above RAI,, the staff finds the applicant has

identified appropriate AMPs for managing the aging effects of the PACHMS component types

that are addressed in this section. 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 PACHMS

components that are identified in this section. 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)(a).

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

Staff Evaluation

The staff reviewed the AMR of the miscellaneous systems in scope for 10 CFR 54;4(a)(2)

component, material, environment, and AERM combinations that are identified in'the sections

below titled "Aging Effects" and "Aging Management Programs." The applicant identified these

combinations in LRA Table 3.3.2-11. For the combinations, the staff verified that the applicant

identified all applicable AERMs and credited appropriate AMPs with managing the AERMs. The

staff also reviewed the applicable UFSAR Supplements for the AMPs to ensure that they

adequately describe the programs.

Aging Effects

Table 2.3.3-11 of the LRA lists individual system components that are within the scope of

license renewal and are subject to AMR. The component types evaluated in this section

include bolting, condenser shell, evaporator housing, filter housing,-flex hoses, heat exchanger

(shell),-heater coil, heater housing, level glass gauge, manifold (piping),-orifices, piping,'pump

casings, strainer housing, tanks, thermowell, trap, tubing, valves, and ventilation unit housing.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel exposed to an external air environment is subject to a loss of material and

loss of mechanical closure integrity. Carbon steel exposed to a treated water, raw water

(fresh), untreated water, or untreated water with boron environment is subject to loss of

material. Carbon steel exposed to an internal environment of steam greater than 132 OC

(270 'F) is subject to cracking-fatigue, loss of material, and loss of material- erosion.

* Stainless steel exposed to an external air environment is subject to loss of mechanical

closure integrity or has no AERMs. Stainless steel exposed to an environment of -

internal treated water, untreated water with boron, or raw water (fresh) is subject to loss

of material. Stainless steel exposed to an untreated water with boron or treated

(borated) water environment is subject to loss of material and cracking. Stainless steel

exposed to an internal untreated water or untreated water with boron environment is

subject to loss of material. Stainless steel exposed to an internal environment of steam

greater than 132 'C (270 F) is subject to cracking-fatigue, loss of material, and loss of

material-erosion. Stainless steel exposed to an internal environment of treated water,

untreated water, or treated borated water greater than 132 'C (270 F) is subject to

cracking-fatigue, loss of material, and cracking.

* Cast iron exposed to an internal environment of steam greater than 132 0C (270 'F) is

subject to cracking-fatigue and loss of material. Cast iron exposed to an environment of

external air or internal treated water is subject to loss of material

* Copper alloy exposed to an internal environment of raw water (fresh), untreated water,

or treated water experiences the aging effect of loss of material. Copper alloy exposed

to an internal environment of steam greater than 132 'C (270 'F)'experiences crackingfatigue. Copper alloy exposed to a external air environment has no AERMs.

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* Glass exposed to air, treated water, untreated water, or untreated water with boron

experiences no aging effects.

* Molded plastic exposed to an air or treated water environment experiences change in

material properties and cracking.

Section 3.3.2.3.12 presents the staff's evaluation of the loss of preload and cracking for closure

bolting.

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI 3.3.2-1

In LRA Tables 3.3.2-1 through 3.3.2-11 for the auxiliary systems, the applicant listed several

components having environments and applicable aging effects with associated AMPs. In the

same columns, for the same component, material, and environment, the applicant listed no

aging effects and no AMPs. For example, in Table 3.3.2-1 1 (page 3.3-130), the applicant -.

identified stainless steel bolting with a function of pressure boundary exposed to an external

environment of air as experiencing loss of material which is managed by the Bolting and

Torquing Activities Program. The same item in the table on page 3.3-130 for the same

component exposed to the same environment has no aging effects listed and therefore requires

no AMP. In addition, in Table 3.3.2-6 (page 3.3-77), copper alloy valves exposed to an external

condensation environment experience a loss of material. The same item in the table on page

3.3-77 for the same component exposed to the same environment has no aging effects listed

and therefore requires no aging management. In RAI 3.3.2-1, the staff asked the applicant to

explain these contradictory entries in the LRA tables.

By letter dated June 8, 2004, the applicant provided the following response applicable to the

miscellaneous systems for RAI 3.3.2-1:

In LRA Tables 3.3.2-1 through 3.3.2-11 for the auxiliary systems, there are six

instances in which a component type lists both an aging effect and "none" for the

same materiaVenvironment combination. While this appears contradictory where

occurring, it is not because each component type in the table actually represents

more than one component in the system. While the components are exposed to

the same overall environment, specific conditions for individual components

differ. The following paragraphs provide additional information for the instances

applicable to the miscellaneous systems:

* LRA Table 3.3.2 11, Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2)

(Page 3.3 130)-stainless steel bolting exposed to air externally

Stainless steel bolting exposed to air in high temperatures systems may

experience loss of pre-load from thermal effects. Therefore, loss of

mechanical closure integrity was identified as an aging effect requiring

management for this stainless steel bolting exposed to air in high

temperature systems. Stainless steel bolting in low temperature systems will

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not experience loss of pre-load from thermal effects.; Also, components in

these systems are not exposed to significant vibration, such as from a diesel

engine. Therefore, no aging effects requiring management were identified

for this stainless steel bolting exposed to air in low temperature systems.

Based on its review, the staff finds the applicant's response to RAI 3.3.2-1 acceptable because

each component type in the table actually represents more than one component in the system,

and while the components are exposed to the same overall environment,-specific conditions for

individual components differ as discussed by the applicant. Therefore, the staff's concerns

described in RAI 3.3.2-1 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 RAI, the staff finds that the aging effects of

the above miscellaneous systems in scope for .10 CFR 54.4(a)(2) 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

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 component

types, 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;

Table 3.3.2-11 of the LRA identifies the following AMPs as managing the aging effects

described above for the miscellaneous systems in scope for 10 CFR 54.4(a)(2):

* Boric Acid Corrosion Prevention Program

* System Walkdown Program

* Bolting and Torquing Activities Program

* Water Chemistry Control Program

* Flow-Accelerated Corrosion Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.2.1, 3.0.3.3.14, 3.0.3.3.2,

3.0.3.3.16, and 3.0.3.1 of this SER, respectively. --

During its review, the staff determined that it needed additional information to complete its

evaluation.

RAI3.3.2.1.11-1

In the LRA, Table 3.3.2-11 (pages 3.3-130 to 3.3-152) identifies the System Walkdown

Program (CNP AMP B.1.38), page B-1 19, for management of various aging effects for several

components with different internal and external environments. The System Walkdown Program

description states that the program is applicable only to situations where the internal and

external environments are the same. A component's external condition may not be

representative of internal material conditions in differing environments. In RAI 3.3.2.1.11-1, the

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staff asked the applicant to justify use of the System Walkdown Program to manage aging

effects for all components identified in Table 3.3.2-11 with different internal and external

environments and also to explain how a system walkdown can inspect and verify proper

management of all internal aging effects.

By letter dated June 8, 2004, the applicant replied as follows:

The statement in the LRA Section B.1.38 Scope section is, "The program is also

credited with managing loss of material from internal surfaces, for situations

where the external surface condition is considered representative of the internal

surface condition and both have the same environment." This statement does

not indicate that the System Walkdown Program is only applicable to situations

where the internal and external environments are the same. The Scope section

also states, "This program includes inspections of external surfaces of CNP

structures and components within the scope of license renewal." This inspection

of external surfaces addresses components subject to aging management

review for 10 CFR 54.4(a)(2), as indicated in LRA Table 3.3.2-11, where the

System Walkdown Program is credited as the sole aging management program

regardless of the environment. For these components, the concern is the impact

of spray or leakage from non-safety-related components on safety related

equipment. Provided the effect of non-safety related component failures on

safety related equipment is managed, safety related equipment will continue to

be capable of performing its required intended functions. The System Walkdown

Program, as described in LRA Section B.1.38, manages aging through visual

inspections of systems and components. This program includes periodic

walkdowns that will detect and correct failures that could result in 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 to prevent recurrence. This is

consistent with the NRC's position provided in the Statements of Consideration

for the Final Part 54 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." While this

discussion pertains to detecting aging related degradation of active components,

it also applies to detecting degradation of the same active components due to

aging related degradation of non-safety related components.

Based on the information presented above, the applicant indicated that the System Walkdown

Program is adequate as an AMP because it includes periodic walkdowns that will detect

conditions that could result in failures caused by exposure to spray or wetting regardless of the

internal or external environments and their aging effects.

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Based on its review, the staff does not find the applicant's response to RAI 3.3.2.1.11-1

acceptable. The applicant's response indicates that the System Walkdown Program is

applicable to situations other than when internal and external environments of the component or

system are the same (for example, inspections of external surfaces of plant structures within

the scope of license renewal). Use of the System Walkdown Program to assess component or

system external conditions is a recognized and accepted aging management approach and is

not an issue or concern. The staff's specific concern, described in RAI 3.3.2.1.11-1, is the

apparent aging management of the internal environments of components/systems by visual

inspection of external surfaces if environmental differences exist between internal and external

surfaces. While external inspection of component condition (e.g. pipes, valves) can indicate the

components' internal condition, this is generally not the case until internal degradation results in

loss of component integrity as might be indicated by a system leak. In such an example, the

leak indicates failure of the structure and or component. The following part of the applicant's

response indicates that the applicant considers component/system aging management and leak

(size and time of spray) management to be equivalent:

This program includes periodic walkdowns that will detect and correct failures that

could result in 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 to prevent recurrence.

In addition, the applicant's response indicates that the current program will manage the size

and duration of leakage so as not to impact the operation of active safety components. Neither

the GALL Report nor the industry recognizes leak management as an acceptable aging

management methodology.

The applicant has not provided sufficient information to demonstrate that the System Walkdown

Program will effectively manage aging effects on internal surfaces of various components in

miscellaneous systems because leakage indicates failure of the structure and or component.

The staff asked the applicant to provide further justification for the use of the System Walkdown

Program to manage aging effects for all components identified in Table 3.3.2-11 with different

internal and external environments sufficiently to maintain the intended function of the

components and ensure that operation of safety related equipment will not be jeopardized

during the period of license renewal. This was identified by the staff as Open Item 3.3.2.1.11-1.

By letter dated January 21, 2005, the applicant provided additional information in response to

Open Item 3.3.2.1.11-1.

As shown in LRA Table 3.3.2-11, in addition to System Walkdown Program, the Water

Chemistry Control Program will manage the effects of aging on the components with an

internal environment of treated water, except for level glass gauges and molded plastic

tanks. Because the glass in the level gauges is inherently resistant to potential aging

effects in air, treated water, raw or untreated water, or untreated borated water

environments, it has no aging effects requiring management. The molded plastic tanks

in the ice condenser system are exposed to an internal treated water environment (i.e.,

glycol mixture) that is monitored by the Auxiliary Systems Water Chemistry Control

Program described in LRA Section B.1.40.3.

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Additionally, as indicated in LRA Table 3.3.2-11, the Flow-Accelerated Corrosion

Program will also manage the effects of aging on components with an internal steam

environment, except for copper heater coils, cast iron strainer housings and carbon steel

traps. I&M will include the auxiliary steam system copper heater coils, cast iron strainer

housings, and carbon steel traps exposed to an internal steam environment in the

Chemistry One-Time Inspection Program, which is described in LRA Section B.1.41.

The remaining components in LRA Table 3.3.2-11 with differing internal and external

environments that credit only the System Walkdown Program for aging management

are exposed to internal raw or untreated water environments. The following table

identifies the fluid-filled mechanical systems that contain these components.

SYSTEM CODE SYSTEM NAME

CF Chemical Feed

CONT Containment

DRAIN Process Drains

LTW Lake Township Water

NESW Non-Essential Service Water

NS Nuclear Sampling

PASS Post-Accident Sampling

RMS Radiation Monitoring

RWD Radioactive Waste Disposal

SD Station Drainage

The following discussion provides additional basis for acceptability of other programs for

managing the effects of aging on the CF, LTW, NESW, and NS systems that have

components containing raw or untreated water.

1. The CF system contains water treated with chemicals to reduce corrosion in the

steam generators. This environment was conservatively classified as untreated

water although it is actually chemically treated.

2. The LTW system contains water that has been chemically treated by the

municipality prior to being used at the site, but was conservatively classified as

untreated water in the aging management review. Because LTW chemistry is

not controlled by CNP, a chemistry control program was not credited in the LRA.

However, as documented in l&M's supplemental response to RAI 3.3.2.1.9-6 in

this letter, the extent of aging effects on security diesel system components

containing LTW will be confirmed by the Chemistry One-Time Inspection

Program, which will inspect a representative sample of 10 CFR 54.4(a)(2)

components in the LTW system.

3. The NS system contains heat exchangers exposed to an internal raw water

(NESW) environment. The NESW system has the same suction source and is

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chemically treated in the same manner as the essential service water (ESW)

system. The Service Water System Reliability Program will manage-the effects

of aging on 10 CFR 54.4(a)(2) components containing NESW, because these

components are fabricated from the same materials and are exposed to the

same environments as components in the ESW-system.

The remaining systems (CONT, DRAIN, PASS, RMS, RWD, and SD) have copper alloy,

carbon steel, stainless steel, or glass components that may be pressurized and contain

raw or untreated water. As discussed previously, glass exposed to raw or untreated'

water exhibits no aging effects requiring management. I&M will include these

10 CFR 54.4(a)(2) components that are subject to aging management review in the

Chemistry One-Time Inspection Program.

Loss of material, if any, from the 10 CFR 54.4(a)(2) components discussed above is

expected to progress slowly. The one-time inspection of these components will provide

assurance that loss of material is occurring at a rate slow enough to ensure that the

intended functions of the components will be maintained during the period of extended

operation. This one-time inspection will be performed near the end of the current

operating term. The visual inspections will identify indications of loss of material. If loss

of material is identified, an evaluation will be performed to confirm that the rate is

sufficiently slow that loss of intended function will not occur during the period of

extended operation. For material and environment combinations with no evidence of

loss of material or with very gradual loss of material, no further actions will be taken.

For material and environment combinations with loss of material rates such that loss of

intended function could occur during the period of extended operation, corrective actions

will be taken in accordance with the Corrective Action Program. Appropriate corrective

actions may consist of component replacement or additional inspections for components

with the material and environment combination in which the excessive loss of material is

found.

The supplemental response is reasonable and acceptable to the staff because the applicant

has provided sufficient information to demonstrate that aging effects on internal surfaces of

various components in miscellaneous systems will be effectively managed by the application of

a combination of the Flow-Accelerated Corrosion Program, Chemistry One-Time Inspection

Program, Water Chemistry Control Program, and the Service Water System Reliability -

Program. The application of the Chemistry One-Time Inspection Program is appropriate for

those components where the loss of material is expected to progress slowly and the applicant

has identified that the inspection will be performed near the end of the current operating term

with appropriate corrective actions. On the basis of the supplemental information submitted by

the applicant, all issues related to Open Item 3.3.2.1.11-1 are resolved. -The application of the

Chemist'y One-Time Inspection Program discussed above is specified in Commitment #39 in

Appendix A of this SER..

RAI 3.3.2.1.11-2

Table 3.3.2-11 of the LRA (page 3.3-131) identifies the System Walkdown Program (CNP AMP

B.1.38), page B-i 19, as managing the loss of material of a stainless steel filter housing in

untreated water with a boron internal environment. This is an example of one of several

stainless steel components for which the applicant identified the System Walkdown Program as

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managing the loss of material in internal environments. The description of the System

Walkdown Program does not address aging management for the loss of material of stainless

steel. In RAI 3.3.2.1.1.1-2, the staff asked the applicant to justify the use of the System

Walkdown Program in managing the loss of material of stainless steel components exposed to

an untreated water with boron internal environment for each component in Table 3.3.2-1 and

also to explain how a system walkdown can inspect and verify proper management of all

internal aging effects.

By letter dated June 8, 2004, the applicant replied to RAI 3.3.2.1.11-2 as follows:

Management of internal loss of material in stainless steel components was an

inadvertent omission from LRA Section B.1.38. This aging effect was included in

the aging management review for filter housings in the radioactive waste

disposal system cited in this RAI as well as other stainless steel components.

For the 10 CFR 54.4(a)(2) component types in LRA Table 3.3.2 11 that credit the

System Walkdown Program, the concern is the impact of spray or leakage from

non-safety-related components onto safety-related equipment. Provided the

effect of non-safety related component failures on safety-related equipment is

managed, safety related equipment will continue to be capable of performing its

required intended functions.

The System Walkdown Program, as described in LRA Section B.1.38, manages

aging through visual inspections of systems and components. This program

includes periodic walkdowns that will detect and correct failures that could result

in 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 to prevent recurrence. This is

consistent with the NRC's position provided in the Statements of Consideration

for the Final Part 54 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." While this

discussion pertains to detecting aging-related degradation of active components,

it also applies to detecting degradation of the same active components due to

aging related degradation of non-safety related components.

Based on the information presented above, the System Walkdown Program is

adequate as an aging management program, because it includes periodic

walkdowns that will detect conditions that could result in failures caused by

exposure to spray or wetting, regardless of the internal or external environments.

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The staff accepts the applicant's response to include aging management for the omitted

stainless steel components. However, the staff does not accept the applicant's response to RAI

3.3.2.1.11-2 concerning the use of the System Walkdown Program to provide adequate aging

management. The applicant's response to RAI 3.3.2.1.11-2 appears to equate leak

management of nonsafety related systems/components to aging management of the same

system/component.

The response indicates that the System Walkdown Program will manage the size and

magnitude of nonsafety related system component leaks sufficiently to ensure minimal impact

on active safety related components. This meaning is substantiated by the applicant's

interpretation of the NRC's SOC for the final rule for 10 CFR Part 54, which it cites in its

response.

Generally, the staff interprets this statement to indicate that failure of an active component

resulting from aging is readily discovered and repaired because of the established effectiveness

of standard industry maintenance programs, as well as active monitoring systems. The

applicant's response appears to equate failure of an active safety related component resulting

from internal component failures to a loss of component functionality caused by nonsafety

related system leakage. The applicant's response further indicates that management of the

size and duration of nonsafety related system leakage would sufficiently ensure functionality of

safety related system active components. Managing the size and duration of spray is not

analogous to preserving the integrity of the pressure boundary and does not provide the same

level of assurance that the functionality of safety related system components will be maintained.

Neither the GALL Report nor the industry recognizes leak management of nonsafety related

systems as an acceptable aging management methodology.

The staff asked the applicant to provide additional justification that the System Walkdown

Program will maintain the intended pressure boundary function for each stainless steel

component defined in Table 3.3.2-11 with an internal environment of untreated borated water,

an external air environment, and the loss of material as the AERM.

By letter dated October 18, 2004, the applicant provided additional information in response to

RAI 3.3.2.1.11-2.

As indicated in l&M's supplemental response to RAI 3.3.2.1.1 1 -1, the stainless

steel components listed in LRA Table 3.3.2-11 with an internal environment of

untreated water with boron and an external air environment will be included in

the Chemistry One-Time Inspection Program to provide assurance that the

pressure boundary function will be maintained through the period of extended

operation.

The supplemental response is reasonable and acceptable to the staff because the applicant

has provided sufficient information to demonstrate that it will effectively manage aging effects

on internal surfaces of stainless steel components in miscellaneous systems by the application

of the Chemistry One-Time Inspection Program. On the basis of the supplemental information

submitted by the applicant, all issues related to RAI 3.3.2.1.11-2 are resolved.

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RAI 3.3.2.1.11-3

Table 3.3.2-11 of the LRA identifies the CNP System Walkdown Program as managing loss of

material, cracking, and change in material properties for the internals of various components

such as condenser shell, evaporator housing, filter housing, flex hose, heat exchanger shell,

heater coil, heater housing, manifold piping, orifice, piping, pump casing, strainer housing,

tanks, thermowell, traps, tubing, valves, and ventilation unit housings. The System Walkdown

Program entails inspections of accessible surfaces during walkdowns. In RAI 3.3.2.1.11-3, the

staff asked the applicant to explain how the System Walkdown Program will detect the loss of

material on the internal surfaces of these components.

By letter dated June 30, 2004, the applicant stated the following:

The System Walkdown Program, as described in LRA Section B.1.38, manages

aging through visual inspections of systems and components. These

inspections will detect loss of material on the internal surfaces of these

components by observing for evidence of leakage on the external surfaces of the

components. For those components where the System Walkdown Program is

credited as the aging management program for the internal surfaces, the

concern is the impact of spray or leakage from nonsafety-related components on

safety-related equipment. By managing the aging effects of nonsafety-related

component failures on safety-related equipment, safety-related equipment will

continue to be able to perform required intended functions.

The System Walkdown Program, as described in LRA Section B.1.38, manages

aging through visual inspections of systems and components. The System

Walkdown Program includes periodic walkdowns that will detect and correct

failures that could result in 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 to prevent recurrence. This is consistent with the NRC's position provided

in the Statements of Consideration for the Final Part 54 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." While this discussion pertains to detecting

aging-related degradation of active components, it also applies to detecting

degradation of the same active components due to aging-related degradation of

nonsafety-related components.

In the information presented above, the applicant stated that the System Walkdown Program is

adequate as an AMP for managing the loss of material on the internal surfaces of components

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listed in LRA Table 3.3.2-11 because it includes periodic walkdowns that will detect and correct

conditions that could result in failures caused by exposure to spray or wetting.

Based on its review, the staff does not find the applicant's response to RAI 3.3.2.1.11-3

acceptable. In the following part of its statement, the applicant's response appears to equate

leak management of nonsafety related systems/components to aging management of the same

system/component:

-The System Walkdown Program, as described in LRA Section B.i.38, manages

;aging through visual inspections of systems and components. This program

includes periodic walkdowns that will detect and correct failures that could result

in 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 to prevent recurrence.

The applicant's response indicates that the System Walkdown Program will manage the 'izeand magnitude of nonsafety related system component leaks sufficiently to ensure minimal

impact on active safety related components. This meaning is substantiated by the applicant's

interpretation of the NRC's SOC for the final rule for 10 CFR Part 54, which the applicant

quoted in its response.

Generally, the staff interprets this statement to indicate that failure of an active component

resulting from aging is readily discovered and repaired because of the established effectiveness

of standard industry maintenance programs, as well as active monitoring systems. Theapplicant's response appears to equate failure of an active safety related component resulting

from internal component failures to a loss of component functionality caused by nonsafety

related system leakage. The applicant's response also indicates that management of the size

and duration of nonsafety related system leakage would sufficiently ensure functionality of

safety related system active components. Managing the size and duration of spray is not

analogous to preserving the functionality of internal components and does not provide the same

level of assurance that the functionality of safety related system components will be maintained.

Neither the GALL Report nor the industry recognizes leak management of nonsafety related

systems as an acceptable aging management methodology.

To further clarify RAI 3.3.2.1.11-3, the staff asked the applicant for additional justification that

the System Walkdown Program will maintain the specified functions for the internals of various

components such as condenser shell, evaporator housing, filter housing, flex hose, heat

exchanger shell, heater coil, heater housing, manifold piping, orifice, piping, pumpcasing,

strainer housing, tanks, thermowell, traps, tubing, valves,-'and ventilation unit housings listed in

Table 3.3.2-11 for which the applicant designated the System Walkdown Program to manage

the aging effects of loss of material, cracking, and change in material properties:

By letter dated October 18, 2004, the applicant referenced the supplemental response to RAI

3.3.2.1.1 1-1 to resolve RAI 3.3.2.1.1 1-3.

The supplemental response is reasonable and acceptable to the staff because the applicant

has provided sufficient information in response to RAI 3.3.2.1.11-1 to demonstrate that it will

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effectively manage aging in the internal surfaces of various components in miscellaneous

systems by the application of a combination of the Flow-Accelerated Corrosion Program,

Chemistry One-Time Inspection Program, Water Chemistry Control Program, and the Service

Water System Reliability Program. On the basis of the supplemental information submitted by

the applicant, all issues related to RAI 3.3.2.1.11-3 are resolved.

In the LRA, the applicant stated that it will manage the loss of material for carbon steel bolting

exposed to ambient air by using the Boric Acid Corrosion Prevention (CNP AMP B.1.4) and

System Walkdown (CNP AMP B.1.38) Programs. The staff's evaluation of these programs

appears in Sections 3.0.3.2.1 and 3.0.3.3.14 of this SER, respectively. Because this approach

is similar to the management recommended by the GALL Report for this material-environment

combination in other auxiliary systems, the staff finds the use of the System Walkdown

Program to be acceptable for these components.

In the LRA, the applicant stated that it will manage the loss of material for carbon steel

component types exposed to ambient air by using the System Walkdown Program. The

applicant will use this program for condenser shell, evaporator housing, heater housing, orifice,

piping, pump casing, strainer housing, tank (including coated carbon steel), thermowell, trap,

valve, and ventilation unit housing component types. The applicant will also use the System

Walkdown Program to manage the loss of material for the internal surfaces of the ventilation

unit housing made of carbon steel. The staff finds this to be acceptable.

For stainless steel exposed to ambient air, the applicant identified no AERM for the bolting, filter

housing, flex hose, manifold, orifice, piping, pump casing, strainer housing, tank, thermowell,

tubing, and valve component types. Because the applicant did not identify any AERMs, and

this is consistent with industry experience, the staff finds the absence of an AMP for stainless

steel components exposed to ambient air to be acceptable.

In the LRA, the applicant stated that it will manage the loss of material for carbon steel

component types exposed to treated water (internal) by using the System Walkdown (CNP

AMP B.1.38) and Water Chemistry Control (CNP AMP B.1.40) Programs. The staff presents its

evaluation of the System Walkdown Program in Section 3.0.3.3.14. In addition, the staff

documents its evaluation of the Water Chemistry Control Program in Sections 3.0.3.2.15,

3.0.3.2.16, and 3.0.3.3.16 of this SER. The applicant uses this program for condenser shell,

evaporator housing, heater housing, orifice, piping, pump casing, strainer housing, tank

(including coated carbon steel), thermowell, and valve component types. The staff finds the

use of the System Walkdown and Water Chemistry Control Programs to be acceptable for

these component types.

For copper alloy heat exchanger (shell), heater coil, manifold, piping, tubing, and valve

component types exposed to ambient air, the applicant identified no aging effects. Because the

applicant did not identify any AERMs, and this is consistent with industry experience, the staff

finds the absence of an AMP for copper alloy components exposed to ambient air to be

acceptable.

In the LRA, the applicant stated that it will manage the loss of material for copper alloy heat

exchanger shell, manifold, piping, tubing, and valve component types in treated water by using

the System Walkdown and Water Chemistry Control Programs. The staff finds the use of the

I

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System Walkdown and Water Chemistry Control Programs to be acceptable for these

component types.

In the LRA, the applicant stated that it will manage the loss of material for the copper alloy

heater coil exposed to steam greater than 132 CC (270 OF) by using the System Walkdown

Program. Although the applicant cited a precedent, the staff could not confirm its applicability in

this case. - It was not clear to the staff how the System Walkdown Program would detect this

aging effect before failure of the component. However, the resolution of related RAI 3.3.2.1.11 -

3 clarifies these issues for the staff.

In the LRA, the applicant stated that it will manage the loss of material for stainless steel in

treated water by using the CNP System Walkdown-and Water Chemistry Control Programs.

This applies to the manifold (piping), orifice, piping,- pump casing, tank, thermowell, tubing, and

valve component types. Because it is similar to the management recommended by the GALL

Report for this material-environment combination in other auxiliary systems, the staff finds the

use of the System Walkdown and Water Chemistry Programs to be acceptable for these

component types.

In the LRA, the applicant stated that it will manage cracking and the loss of material for

stainless steel manifold, piping, pump casing, thermowell, tubing, and valves exposed to

treated, borated water by using the Water Chemistry Control Program with the System

Walkdown Program. Because this approach is similar to the management recommended by

the GALL Report for this material-environment combination in other auxiliary systems, the staff

finds the use of the System Walkdown and Water Chemistry Programs to be acceptable for

these component types.

In the LRA, the applicant stated that it will manage the loss of material for cast iron pump

casing and strainer housing component types in air by using the System Walkdown Program.

Because the aging effects for this material are similar to those for carbon steel in this

environment and because the program is acceptable for management of this aging effect in

carbon steel, the staff finds its use acceptable.

In the LRA, the applicant stated that it will manage the loss of material and cracking in stainless

steel tubing and valves exposed to treated water greater than 132 OC (270 OF) and treated,

borated water greater than 132 6C (270 0

F) by using a water chemistry control program

consistent with the GALL Report. Because this approach is similar to the management of

cracking of stainless steel in this environment in other non-Class 1 systems, the staff finds the

use of the System Walkdown and Water Chemistry Control Programs to be acceptable for

these component types.

In the LRA, the applicant stated that there are no aging effects for the level glass gauge

component type (glass) in an external environment of air or an internal environment of treated

water, untreated water or untreated water with boron. The GALL Report does not discuss

similar component, material, and environment combinations. On the basis that these

components have no AERMs, the staff finds the absence of an AMP for glass to be 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 miscellaneous systems in

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scope for 10 CFR 54.4(a)(2) component types that are addressed in this section. 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 miscellaneous

systems in scope for 10 CFR 54.4(a)(2) components that are identified in this section. 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).

3.3.2.3.12 Generic Issues for the Auxiliary Systems

For bolting in the auxiliary systems, the applicant did not address the aging effects of cracking

due to SCC for high-strength bolts or the loss of preload. The staff asked the applicant to

address these issues for auxiliary system bolting. The staff discusses its evaluation of the

applicant's response and resolution of the staff's concerns as part of the evaluation of RAI

B.1.2-1 in Section 3.0.3.3.2 of this SER.

3.3.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the auxiliary system components that are within the

scope of license renewal and subject to an AMR so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4 Aging Management of Steam and Power Conversion Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

steam and power conversion systems components and component groups associated with the

following systems:

* main feedwater system

* main steam system

* auxiliary feedwater system

* blowdown 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 AMR of the main feedwater,

main steam, AFW, and blowdown system components and component types listed in Tables

2.3.4-1 through 2.3.4-4 of the LRA. The applicant also listed the materials, environments,

AERMs, and AMPs associated with each system.

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In Table 3.4.1,- "Summary of Aging Management Programs for the Steam and Power

Conversion System Evaluated in Chapter VIII 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 main feedwater, main steam, AFW, and blowdown 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 Section 3.4 of the LRA to understand the applicant's review process. The

staff determined whether the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the main feedwater, main steam, AFW, and

blowdown system components that are within the scope of license renewal and subject to an

AMR, in order that their intended functions will be 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 verify that

the material presented in the LRA is appropriate and that the applicant identified the necessary

GALL AMRs. The staff summarizes its audit and review findings in Section 3.4.2.1 of this SER.

The staff also audited those AMRs that are consistent with the GALL Report'and for which

further evaluation is recommended. The staff verified that the applicant's further evaluations

are consistent with the acceptance criteria in Section 3.4.3.2 of the SRP-LR. The staff

summarizes its audit and review findings in Section 3.4.2.2 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 whether it listed the appropriate aging effects for the combination of materials

and environments s'pecified. The staff summarizes its audit and review findings in Section

3.4.2.3 of this SER.

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

steam and power conversion systems.

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.

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Il

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

the GALL Report

Component Aging Effect ' AMPInGALL -AMPinLRA :. StaffEvaluation

- Group Mechanism- Report -

Piping and fittings Cumulative fatigue TLAA, evaluated in TLAA Consistent with

in main feedwater damage accordance with GALL, which

line, steamline, 10 CFR 54.21(c) recommends further

and AFW piping evaluation (See

(PWR only) (Item Section 3.4.2.2.1)

Number 3.4.1-1)

Piping and fittings, Loss of material due Water chemistry Water Chemistry Consistent with

valve bodies and to general (carbon and one-time Control Program GALL, which

bonnets, pump steel only), pitting, inspection (B.1.40); Wall recommends further

casings, tanks, and crevice Thinning Monitoring evaluation (See

tubes, tubesheets, corrosion Program (B.1.39) Section 3.4.2.2.2)

channel heads,

and shells (except

main steam

system) (Item

Number 3.4.1-2)

AFW piping (Item Loss of material due Plant specific Service Water Consistent with

Number 3.4.1-3) to general, pitting, System Reliability GALL, which

and crevice Program (B.1.29), recommends further

corrosion; MIC; and Water Chemistry evaluation (See

biofouling Control Program- Section 3.4.2.2.3)

Primary and

Secondary Water

Chemistry

Programs

(B.1.40.1), and

System Testing

Program(B.1.37)

Oil coolers in AFW Loss of material due Plant specific Oil Analysis Consistent with

system (lubricating to general (carbon (B.1.23) GALL, which

oil side possibly steel only), pitting, recommends further

contaminated with and crevice evaluation (See

water) (Item corrosion; MIC Section 3.4.2.2.5)

Number 3.4.1-4)

External surface of Loss of material due Plant specific System Walkdown Consistent with

carbon steel to general corrosion Program (B.1.38) GALL, which

components (Item recommends further

Number 3.4.1-5) evaluation (See

Section 3.4.2.2.4)

Carbon steel Wall thinning due to Flow-accelerated Flow-Accelerated Consistent with

piping and valve Flow-accelerated corrosion Corrosion Program GALL, which

bodies (Item corrosion (B.1.12) recommends no

Number 3.4.1-6) further evaluation

(See Section

3.4.2.1)

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. Component, Aging Effect : AMP In GALL, AMP In LRA : Staff Evaluation -Group ' Mechanism 'Repor r " ... . -.

Carbon steel Loss of material due Water chemistry Water Chemistry Consistent with

piping and valve to pitting and crevice Control Program GALL, which

bodies in main corrosion (B.1.40); Wall recommends no

steam system Thinning Monitoring further-evaluation

(Item Number . Program (B.1.39) (See Section

3.4.1-7) ' 3.4.2.1)

Closure bolting in Loss of material due Bolting integrity , System Walkdown Consistent with

high-pressure or to general corrosion; Program (B.1 .38); GALL, which

high-temperature crack initiation and, Bolting and recommends no

systems (Item growth due to cyclic Torquing Activities further evaluation

Number 3.4.1-8) loading and/or SCC Program (B.1.2) (See Section

3.4.2.1)

Heat exchangers . Loss of material due Open-cycle cooling Not Applicable Consistent with '

and coolers/ to general (carbon water system GALL, which

condensers by steel only), pitting, recommends no

open-cycle cooling and crevice further evaluation

water (Item corrosion; MIC; (See Section

Number 3.4.1-9) biofouling; and 3.4.2.1)

buildup of deposits

due to biofouling -- ._ -

Heat exchangers Loss of material due Closed-cycle' Not Applicable Consistent with

and coolers/ to general (carbon cooling water GALL, which

condensers by steel only), pitting, system recommends no

closed-cycle and crevice further evaluation

cooling water (Item corrosion (See Section

Number 3.4.1 -10) 3.4.2.1)

External surface of Loss of material due Aboveground Not Applicable Consistent with

aboveground to general (carbon carbon steel tanks GALL, whichcondensate steel only), pitting, recommends no

storage tank (Item and crevice further evaluation

Number 3.4.1-11) corrosion (See Section

3.4.2.1)

External surface of Loss of material due Buried piping and Not Applicable Consistent with

buried condensate to general, pitting, tanks surveillance GALL. which

storage tank and and crevice - recommends no

AFW piping (Item' corrosion, and MIC or further evaluation

Number 3.4.1-12) (See Section

3.4.2.1)

. Buried piping and . Consistent with

tanks inspection GALL, which

recommends further

: -.- - evaluation (See

Section 3.4.2.2.5)

External surface of Loss of material due Boric acid corrosion Not Applicable Consistent with

carbon steel - to boric acid - GALL, which

components (Item corrosion recommends noNumber 3.4.1-13) further evaluation

(See Section _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 3 .4 .2 .1 )

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The staff's review of the steam and power conversion system and associated components

followed one of several approaches. One approach, documented in Section 3.4.2.1 of this

SER, involved the staff's 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 of this SER,

involved the staff's 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 for

which further evaluation is recommended. A third approach, documented in Section 3.4.2.3 of.

this SER, involves the staff's 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. The staff documents its review of AMPs that are credited to

manage or monitor aging effects of the steam and power conversion system components in

Section 3.0.3 of this SER.

3.4.2. 1 Aging Management Evaluations That Are Consistent with the GALL Report, for Which

No Further Evaluation Is Required

Summary of Technical Information in the Application

In Section 3.4.2.1 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

main steam, main feedwater, blowdown, and AFW system components:

* Bolting and Torquing Activities Program

* Flow-Accelerated Corrosion Program

* System Walkdown Program

* Water Chemistry Control Program

* Heat Exchanger Monitoring Program

* Oil Analysis Program

* Preventive Maintenance Program

* Wall Thinning Monitoring Program

Staff Evaluation

In Tables 3.4.2-1 through 3.4.2-4 of the LRA, the applicant provided a summary of AMRs for

the main feedwater, main steam, AFW, and blowdown system 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 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

Report evaluation.

The applicant provided a note for each AMR line item. The notes describe the alignment of the

information in the tables with the information in the GALL Report. The staff audited those

AMRs with Notes A through E, where applicable, which indicate that the AMR is consistent with

the GALL Report.

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Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP identified by the applicant is

consistent with the AMP identified in the GALL Report.: The staff audited these line items to

verify consistency with the GALL Report and the validity of the AMR for the site-specific

conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the applicant took some exceptions tothe

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that it has reviewed and accepted the applicant's

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

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, but consistent with the

GALL Report for material, environment, and aging effect. In addition, the applicant took some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component applies to the component under review. The staff verified whether it

reviewed and accepted the applicant's 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 credits a different AMP. 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 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

consistent with the GALL Report, are indeed consistent with the AMRs in the GALL Report.

Therefore, the staff finds that the applicant identified the applicable aging effects, and that

these are appropriate for the combination of materials and environments listed.

On the basis of its audit and review, the staff concludes that the applicant demonstrated that it

will adequately manage the effects of aging so that the intended functions will be consistent

*with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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-I

Conclusion

The staff verified 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 AMR results, which the applicant claimed to be consistent with the GALL Report, are

indeed consistent with the AMRs in the GALL Report. Therefore, the staff finds that the

applicant demonstrated that it will adequately manage the effects of aging for these

components so that their intended functions will be consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2 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 3.4.2.2 of the LRA, the applicant provided 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, MIC, and biofouling

* general corrosion

* loss of material due to general, pitting, crevice corrosion, and MIC

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 further evaluated. In addition, the staff reviewed the applicant's further

evaluations against the criteria contained in Section 3.4.2.2 of the SRP-LR. The staff

documents details of its audit and review in the audit and review report.

The GALL Report indicates that the applicant should perform further evaluation for the aging

effects described in the following sections of this SER.

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, and TLAAs must be

evaluated in accordance 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.

3.4.2.2.2 Loss of Material due to General, Pitting, and Crevice Corrosion

Section 3.4.2.2.2 of the SRP-LR states that the management of the loss of material due to

general, pitting, and crevice corrosion should be further evaluated for carbon steel piping and

L

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fittings, valve bodies and bonnets, pump casings, pump suction and discharge lines, tanks,

tubesheets, channel heads, and shells (except for main'stdam system components) and for the

loss of material due to pitting and crevice corrosion for stainless steel tanks and heat

exchanger/cooler tubes. The Water Chemistry Control Program relies on monitoring and

control of water chemistry based on the guidelines of EPRI TR-1 02134, Revision 3, for the

Secondary Water Chemistry Control Program to manage the effects of the loss of material due

to general, pitting, or crevice corrosion. However, corrosion may occur at locati0nsof stagnant

flow conditions. -Therefore, the applicant should verify the effectiveness of the Water Chemistry

Control Program to ensure that corrosion does not occur. 'The GALL Report recommends

further evaluating programs to manage the loss of material due to general, pitting, and crevice

corrosion in order to verify the effectiveness of the Water Chemistry Control Program. A

one-time inspection of select components and susceptible locations is an acceptable method to

ensure that corrosion does not occur, and that the component's intended function will be

maintained during the period of extended operation.

The GALL Report recommends GALL AMP XL.M32 for managing this aging effect.

In LRA Section 3.4.2.2.2, the applicant addressed the loss of material due to general, pitting,

and crevice corrosion that could occur on the internal surfaces of piping and fittings, valve

bodies and bonnets, piping manifolds, orifices, pump casings, strainer housings, tanks, tubes,

tubesheets, channel heads, and shells (excluding the main steam system). General corrosion

applies only to carbon steel components; pitting and crevice corrosion' apply to both carbon and

stainless steel components and to the cast iron strainer housings. In LRA Section 3.4.2.2.2, the

applicant also addressed the GALL Report recommendation for further evaluation to verify the

effectiveness of the Water Chemistry Control Program in managing the loss of material due to

general, pitting, and crevice corrosion.

Regarding the components for which such an evaluation is required, the applicant credited the

Water Chemistry Control-Primary and Secondary Water Chemistry Control Program (CNP

AMP B.1.40.1), with enhancements, to manage the loss of material by mitigating damage

caused by corrosion. Section 3.0.3.2.15 of this SER evaluates CNP AMP B.1.40.1. Consistent

with the GALL Report, the applicant supplemented its Primary and Secondary Water Chemistry

Control Program with the-Wall Thinning Monitoring Program (CNP AMP B.1.39) (AFW system

components only) and the Water Chemistry Control-Chemistry One-Time Inspection Program

(CNP AMP B.1.41) as the verification programs for the steam and power conversion system

components.

Section 3.0.3.3.15 of this SER documents the staff's evaluation of CNP AMP B.1.39, which is a

plant-specific program. The Water Chemistry Control-Chemistry'One-Time Inspection '-

Program is a new program that the applicant stated is consistent with GALL AMP XI.M32 but of

a more limited scope. The staff documents'its evaluation of CNP AMP B.1.41 in Section

3.0.3.3.17 of this SER.

3.4.2.2.3 Loss of Material due to General, Pitting, and Crevice Corrosion, Microbiologically

Influenced Corrosion,-and Biofouling

Section 3.4.2.2.3 of the SRP-LR states that the loss of material due to general, pitting, and

crevice corrosion, MIC, and biofouling could occur in carbon steel piping and fittings for

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untreated water from the backup water supply in the AFW system. The GALL Report recommends further evaluation to ensure that these aging effects are adequately managed.

In LRA Section 3.4.2.2.3, the applicant addressed the loss of material in carbon steel piping and

fittings for untreated water from the backup water supply in the AFW system.

In the LRA, the applicant stated that it addressed the portion of the lines from the ESW system to the AFW system that are exposed to untreated water as part of the ESW system (Item 3.3.1-17 in LRA Table 3.3.1). The staff finds that, with exceptions and enhancement, the

Service Water System Reliability Program (CNP AMP B.1.29) is consistent with GALL AMP

XL.M20 as discussed in Section 3.0.3.2.11 of this SER.

The applicant stated that CNP AMP B.1.40.1 and the System Testing Program (CNP AMP

B.1.37), which manage the loss of material and fouling, supplement CNP AMP B.1.29. The

staff evaluates these AMPs in Sections 3.0.3.2.15 and 3.0.3.3.13 of this SER, respectively. The

staff finds that, although biofouling alone is not an aging effect, the AMPs manage the effects

that may result from biofouling in carbon steel piping and fittings exposed to an internal

environment of untreated water from the backup water supply in the ESW system.

The staff finds that the applicant demonstrated that it will adequately manage the effects of

aging for the loss of material due to general, pitting, and crevice corrosion, MIC, and biofouling

so that the intended functions will be consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2.4 General Corrosion

Section 3.4.2.2.4 of the SRP-LR states that the 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 100 0C (212 'F). The GALL Report recommends further

evaluation to ensure that this aging effect is adequately managed.

In LRA Section 3.4.2.2.4, the applicant stated that the loss of material due to general corrosion

could occur on external surfaces of carbon steel SCs, including closure bolting, and the cast

iron strainer housing in the AFW system. The strainer housing is included because industry experience has demonstrated that cast iron is subject to the same aging effects as carbon steel

in this environment.

In the LRA, the applicant credited the System Walkdown Program (CNP AMP B.1.38), with

enhancements, with managing the loss of material for the external surfaces of carbon steel

SCs, including indoor and outdoor bolting, and the cast iron strainer housing. This is consistent

with the GALL Report. The staff reviewed the applicant's enhanced System Walkdown

Program and concludes that the program is acceptable. The staff documents its evaluation of

this program in Section 3.0.3.3.14 of this SER.

The staff finds that the applicant demonstrated that it will adequately manage the effects of

aging for loss of material due to general corrosion so that the intended functions will be

consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.4.2.2.5 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

Section 3.4.2.2.5 of the SRP-LR addresses the loss of material due to general corrosion

(carbon steel only), pitting, 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 AFW system. The GALL Report recommends further evaluation to ensure the

adequate management of these aging effects.

Section 3.4.2.2.5 of the SRP-LR also addresses the loss of material due to general corrosion,

pitting, crevice corrosion, and MIC which could occur in underground piping and fittings and

emergency CST in the AFW system and the underground CST in the condensate system. The

Buried Piping and Tankslinspection Program relies on industry practice, frequency of pipe

excavation, and operating experience to manage the effects of loss of material resulting from

general corrosion, pitting, crevice corrosion, and MIC. The effectiveness of the Buried Piping.

and Tanks Inspection Program should be verified to evaluate an applicant's inspection -

frequency and operating experience with buried components, ensuring that a loss of material is

not occurring.

In LRA Section 3.4.2.2.5, the applicant addressed (1) the loss of material due to general

corrosion, pitting, crevice corrosion, and MIC in carbon steel components exposed to lubricating

oil in the AFW system and (2) the loss of material in underground piping and fittings and

storage tanks for steam and power conversion systems. The components exposed to an

internal environment of lubricating oil and subject to this aging effect are the AFW system

carbon steel piping, pump casings, governor housing, heat exchanger shell, and sight glass

housing.

The applicant stated that the Oil Analysis Program (CNP AMP B.1.23) manages the loss of

material aging effect for carbon steel components exposed to an internal environment of

lubricating oil in the AFW system. The staff finds that the applicant's oil analysis program

adequately manages the effects of aging of loss of material for carbon steel components

exposed to lubricating oil. The staff documents its evaluation of this AMP in Section 3.0.3.3.8

of this SER.

The staff confirmed that CNP has no buried components subject to an AMR in steam and

power conversion systems.

The staff finds that the applicant demonstrated that it will adequately manage the effects of

aging for the loss of material due to general, pitting, and crevice corrosion and MIC so that the

intended functions will be consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.4.2.2.6 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.

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I

Conclusion

On the basis of its review of 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 determines that the applicant adequately addressed

the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations

against the criteria contained in the SRP-LR. Because the applicant's AMR results are

consistent with the GALL Report and the SRP-LR, the staff 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 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 or Not Addressed in the GALL Report

Staff Evaluation

The staff reviewed the AMR of the steam and power conversion system component, material,

environment, AERM combinations that are not addressed in the GALL Report, as well as

specific combinations addressed in the GALL Report within the scope of review. The AERM

combinations not addressed in the GALL Report are addressed in notes F through J in LRA

Tables 3.4.2-1 through 3.4.2-4. The staff verified that the applicant identified all applicable

AERMs and credited the appropriate AMPs for managing the AERMs. The staff also reviewed

the applicable UFSAR Supplements for the AMPs to ensure that they adequately describe the

AMPs.

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.

Note J indicates that neither the identified component nor the material and environment

combination is evaluated in the GALL Report.

Aging Effects

Tables 3.4.2-1 through 3.4.2-4 of the LRA list 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 piping, manifold (piping), valves, bolting, orifices, tubing, fittings, heat

exchanger tubes, tanks, and sight glass.

For these component types, the applicant identified the following materials, environments, and

AERMs:

I

I

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* Stainless steel components exposed to an external air environment are subject to an

aging effect of loss of mechanical closure integrity.

* Stainless steel components exposed to a steam or treated water (greater than 1320C

(270 0)) environment are subject to aging effects of cracking fatigue and loss of

material.

* Carbon steel components exposed to an external air environment are subject to aging

effects of loss of mechanical closure integrity and loss of material.

* Carbon steel components exposed to steam (greater than 132 0C (270 OF)) or internal

treated water are subject to the aging effect of loss of material.

* Copper alloys exposed to an environment of treated water or lubricating oil are subject

to the aging effects of loss of material and fouling.

* Elastomers exposed to air or treated water environments are subject to the aging effects

of change in material properties and cracking.

The staff reviewed the information in LRA Sections 2.3.4 and 3.4, including Tables 3.4.1 and

3.4.2-1 through 3.4.2-4. During its review, the staff determined that it required additional

information to complete its review.

By letter dated May 26, 2004, the staff requested that the applicant provide additional

information on the issues described in the system-specific RAls. By letter dated June 30, 2004,

the applicant responded to the RAls. In the remainder of this section, the staff evaluates those

RAls and the applicant's responses which are applicable to several or all subsystems of the

steam and power conversion system. The staff evaluates the subsystem-specific RAls and

responses in Sections 3.4.2.3.1 through 3.4.2.3.4 of this SER.

RAI 3.4-2

Table 3.4-1, Item 1, of the LRA identifies the applicant's aging management approach for

cumulative fatigue damage of piping and fittings in the main feedwater line, the steamline, and

AFW piping. In the "Discussion" column for this item,- the LRA states, "See Section 4.3 [of the

LRA]."

The applicant states in Section 4.3 of the LRA that, based on the screening criteria, it

determined that the main feedwater, main steam, AFW, and blowdown systems exceed the

screening criteria. The applicant evaluated the piping components that exceed the screening

criteria for their potential to exceed 7000 thermal cycles in 60 years of plant operation. The

applicant determined that none of the piping components in the steam and power conversion

system will exceed 7000 cycles during the period of extended operation.

In RAI 3.4-2, the staff requested that the applicant provide the highest estimated number of

thermal cycles, as well as the basis for derivation for each component type identified in LRA

Tables 3.4.2-1 through -4 for which the applicant designated the TLAA of metal fatigue as the

AMP.

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The staff also requested that the applicant clarify whether, for certain components whose

material or aging effect is not specified in the GALL Report (designated as 'F' and 'I'

respectively in the notes), it performed the thermal cycle evaluation as described in Section

4.3.1.1.2 of the SRP-LR. If so, the staff asked the applicant to note whether its TLAA program

is consistent with the SRP-LR. If not, the staff asked the applicant to explain any differences.

In addition, the staff requested the applicant to address how it considered unanticipated

transients and thermal stratification in its estimation.

In its response, the applicant stated the following:

The evaluation of cracking by fatigue was identified as a TLAA for piping and

valves in the main feedwater system, main steam system, auxiliary feedwater

(AFW) system (i.e., steam supply to the AFW pump and exhaust), and blowdown

system. Mechanical components identified as susceptible to cracking by fatigue

were designed in accordance with USAS B31.1.

Main feedwater system and main steam system thermal cycles anticipated over

60 years correspond to heatup and cooldown cycles, for which CNP is restricted

to 200 cycles. Therefore, main feedwater and main steam piping and valves will

not experience 7,000 cycles during the period of extended operation.

The steam supply to the AFW pump turbine and the turbine exhaust are

exercised during AFW pump testing and during certain plant transients in which

normal feedwater is unavailable. Significantly fewer than 7,000 equivalent fulltemperature cycles of these components are expected during the period of

extended operation, because the plant is restricted to 400 reactor trips and

testing of the AFW pumps is performed on an 18-month cycle, in accordance

with plant Technical Specifications.

The steam generator blowdown system is placed in service primarily during

startup to obtain the required water chemistry for normal operation. The plant is

restricted to 200 heatups and cooldowns; therefore, this system will not exceed

200 equivalent full-temperature cycles. After startup, the steam generator

blowdown system is used when corrections are required for secondary water

chemistry. Sample lines that are connected to the steam generator blowdown

system are in service continuously when blowdown is being exercised. Through

the period of extended operation, the system is not expected to exceed 5,000

full-temperature equivalent cycles to correct secondary water chemistry during

normal operation (assuming two secondary water chemistry corrections per

week for 60 years, with an 80 percent capacity factor). Therefore, steam

generator blowdown system will not experience 7,000 thermal cycles during the

period of extended operation.

The thermal cycle evaluations discussed in this RAI response pertain to those

performed for USAS B 3.1.1 piping, as discussed in NUREG-1 800,

Section 4.3.1.1.2 , "ANSI B31A.1"

The thermal cycle assessment for USAS B3.1.1 piping, as described in NUREG1800, Section 4.3.1.1.2, was performed for components that may operate at

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temperatures that exceed the screening criteria provided in LRA Section 4.3.2.

In addition to the 10 CFR 54.21 (a) screening criteria, each mechanical system

reviewed for the CNP IPAw'was also screened to identify po6tential metal fatigue

TLAAs. This was accomplished by identifying non-Class 1 components that may

operate at temperatures in excess of 104 0 C (220 0F) for carbon steel, or 132 0C

(270 OF) for austenitic stainless steel during normal or upset conditions. Fatigue

evaluations of components that exceeded the screening criteria were identified

as TLAAs for license renewal. These screening criteria are consistent with the

screening criteria described in Section 4.3.2 of the St. Lucie Units 1 and 2 LRA.

The threshold value of 104 OC (220 OF) for thermal fatigue of carbon steel piping

is based on an initial ambient temperature of .21 'C (70 OF) with a minimum

temperature differential of 66 CC (150 OF). The threshold value of 132 OC (270

OF) for thermal fatigue of stainless steel piping is based on an initial ambient

temperature of 21 .

0

C (70 OF) with a minimum temperature differential of 93 0C

(200 OF). The minimum temperature differentials are based on industrysponsored investigations and evaluations of thermal fatigue in nuclear plant

piping systems, as presented in EPRI TR-104534.

Thermal stratification in Class 1 portions of systems attached to the RCS is

addressed in the l&M responses to NRC Bulletin 88-08, "Thermal Stresses in

Piping Connected to Reactor Coolant Systems," (LRA References 4.3-11

through 4.3-15) as summarized in LRA Section 4.3.1.

UFSAR Section 4.1.4 describes cyclic load considerations. RCS components

were designed to withstand the effects of cyclic loads resulting from reactor

system temperature and pressure changes. These cyclic loads are introduced

by normal power changes, reactor trips,,and startup and shutdown operations.

The number of thermal and loading cycles used for design purposes appears in

UFSAR Table 4.1-10. To provide a high degree of integrity for the equipment in

the RCS, the transient conditions selected for equipment fatigue evaluation were

based on a conservative estimate of the magnitude and frequency of the

temperature and pressure transients resulting from normal operation, normal and

abnormal load transients, and accident conditions. To a large extent, the

specific transient operating conditions considered for equipment fatigue analyses

were based upon engineering judgment and experience. The transients chosen

are representative of transients which prudently should be considered to occur

during plant operation and which are sufficiently severe or may occur frequently

to be of possible significance to component cyclic behavior.

With regard to the staff's concern related to unanticipated transients, the applicant stated that it

did not account for unanticipated transients in its methodology, and that if they occur, they are

identified and evaluated for impact on design thermal and loading cycles through the Corrective

Action Program. The applicant monitors transients in critical Class 1 systems. The staff finds

the applicant's response reasonable and acceptable because the applicant provided a

satisfactory description of how thermal cycle evaluation is performed. The staff's concerns in

RAI 3.4-2 are therefore resolved.

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RAI 3.4-4

The Bolting and Torquing Activities Program (CNP AMP B.1.2), an existing plant-specific

program, is credited with managing the loss of mechanical closure integrity. The program

covers bolting in high-temperature systems and in applications subject to significant vibration.

The staff notes that the GALL Report recommends GALL AMP XL.M 18 for monitoring the loss

of material, cracking, and the loss of preload. In addition, accepted bolting integrity programs (such as EPRI TR-1 04213) recommend monitoring for the loss of preload as one of the

parameters to be monitored/inspected. Monitoring for cracking of high-strength bolts (actual yield strength equal to or greater than 150 ksi) is also recommended.

As such, in RAI 3.4-4 the staff requested the applicant provide the following information:

A. Identify the areas of the Bolting Integrity Program at D. C. Cook which are

consistent with the AMP XI.M.18 in the GALL report, and also those aspects in

which it is different.

B. Discuss how the loss of preload aging effect would be managed by the Bolting and Torquing Activities AMP at D. C. Cook.

C. Discuss the inspections associated with the Bolting and Torquing Activities AMP

at D. C. Cook which may be beyond the requirements of ASME Section Xl.

D. Are there any high strength bolts included within the boundary of these systems (Engineered Safety Features and Steam & Power Conversion Systems)?

E. The occurrence of SCC in stainless steel bolts can depend on a combination of

factors such as stainless steel grade, method of hardening (for example, strain,

precipitation or age hardening) environment and stress levels. Discuss how

these factors were taken into account to determine whether or not SCC is an

applicable aging effect.

In its response the applicant stated the following:

A. The Bolting and Torquing Activities Program is an existing plant-specific

program that was not compared to NUREG-1 801, Section XI.M1 8.

The program described in NUREG-1 801, Section XI.M1 8, 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 (see response to paragraph (e) below) and loss of material

is managed by other programs identified in LRA Appendix B, as indicated

in LRA Section 3.0 tables. Thus, the plant-specific Bolting and Torquing Activities Program, used only to manage loss of mechanical closure

integrity, is not comparable to AMP XI.M1 8 of NUREG-1 801.

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In LRA Section B.1.2, the ten attributes of the Bolting and Torquing

Activities Program were provided to allow for its assessment independent

of NUREG-1 801, Section XI.M18.

B. Loss of preload is managed by the Bolting and Torquing Activities

Program by assuring that proper torque values are applied to bolted

closures. With proper design of bolted closures, selection of appropriate

torque values prevents loss of preload due to vibration or thermal cycles.

C. The Bolting and Torquing Activities Program is a preventive program.

The associated inspections are a check of the bolt torque performed prior

to joint assembly and verification of proper gasket compression after

torquing.

D. CNP piping material specifications do not permit, nor have they

historically permitted, high-strength bolting in non-Class 1 systems.

Review of operating experience did not identify problems with cracking of

high-strength bolting in air environments.

E. SCC occurs through the combination of high stress (both applied and

residual tensile stresses), a corrosive environment, and a susceptible

material. Proper lubricants and sealant compounds are used to minimize

the potential for SCC. The Bolting and Torquing Activities Program

provides for selection of appropriate lubricants and sealants to preclude

introduction of significant contaminants.

In the aging management reviews, sufficient stress to initiate SCC was

assumed if stainless steel bolting was subject to a corrosive environment.

However, SCC very rarely occurs in austenitic stainless steels below

140 OF. Although SCC has been observed in stagnant, oxygenated

borated water below 140 0F, all of these instances have identified a

significant contaminant (halogens, specifically chlorides) affecting the

failed components. Since stainless steel bolted closures are exposed to

ambient temperature rather than high temperature process fluids,

cracking of non-Class 1 stainless steel bolting is not an aging effect

requiring management.

The staff discusses its evaluation of the applicant's response and resolution of the staff's

concerns as part of the evaluation of RAI B.1.2-1 in Section 3.0.3.3.2 of this SER.

RAI 3.4-5

The applicant did not identify any aging effect for stainless steel tubes and tube fittings or

valves (body only) in the reactor building environment. In RAI 3.4-5 the staff requested the

applicant to justify this omission. If insignificant concentration of contaminants comprised part

of the justification, the applicant was asked to provide the acceptance criterion and the

verification/inspection activities on susceptible locations to justify the position.

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The applicant stated the following in its response:

The environment is maintained below 120 OF in the containment lower

compartment and below 100 'F in the containment upper compartment.

Stainless steel components are not susceptible to general corrosion in an air

environment regardless of humidity level due to the inherent resistance of

stainless steel to corrosion. Loss of material due to pitting or crevice corrosion

requires a wetted environment (such as condensation (alternating wetting and

drying which concentrates contaminants), pooling of liquid, or submergence) to

be considered an aging effect requiring management. The containment

environment does not contain significant moisture such that loss of material due

to pitting and crevice corrosion is an aging effect requiring management for

stainless steel components. Stainless steel components that are subject to a

wetted environment are included in the LRA aging management review results

tables with an environment other than air (e.g., condensation, raw water, treated

water). In addition, a review of plant operating experience identified no

significant degradation of stainless steel components due to the containment

environment.

The staff finds the applicant's response reasonable and acceptable because the applicant provided the specific environments to which the stainless steel components are exposed. The

staff is satisfied that the loss of material due to pitting and crevice corrosion of stainless steel

components under these conditions is not likely to occur.

RAI 3.4-10

Tables 3.4.2-1 through -4 of the LRA identify the loss of material and cracking as an aging effect for various stainless steel components in treated water and steam environments. The

applicant credited the Water Chemistry Control Program to manage this aging effect. Stainless

steels are susceptible to the loss of material in this type of environment, and the GALL Report recommends that, for the loss of material due to pitting and crevice corrosion, the effectiveness

of the Water Chemistry Control Program should be verified to ensure that significant degradation is not occurring. In RAI 3.4-10, the staff requested the applicant to confirm that the

One-Time Inspection Program discussed in Appendix B to the LRA will verify the effectiveness

of the Water Chemistry Control Program for various stainless steel components in treated water

and steam environments.

In its response, the applicant stated the following:

NUREG-1 801, Section XI.M2, 'The Generic Aging Lessons Learned (GALL)

report identifies those circumstances in which the water chemistry program is to

be augmented to manage the effects of aging for license renewal.... Accordingly, in certain cases as identified in the GALL report, verification of the effectiveness

of the chemistry control program is undertaken to ensure that significant degradation is not occurring.... As discussed in the GALL report for these

specific cases, an acceptable verification program is a one-time inspection of

selected components at susceptible locations in the system." For steam and

power conversion systems stainless steel components, the GALL Report only recommends augmentation of the Water Chemistry Control Program for the

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condensate storage tank and heat exchanger tubes. Confirmation of the Water

Chemistry Control Program's effectiveness is not recommended for other

stainless steel components.

The Chemistry One-Time Inspection Program will verify the effectiveness of the Water

Chemistry Control Program, as described in LRA Section B.1.41. Inspections and

examinations performed under this program will verify the effectiveness of the Water Chemistry

Control Program in managing the aging effects of the loss of material and cracking for stainless

steel in treated water and steam environments, as specified in the GALL Report.

The staff finds the applicant's.response to RAI 3.4-10 reasonable and acceptable because the

applicant clarified how the Chemistry One-Time Inspection Program will verify the effectiveness

of the Water Chemistry Control Program in managing the aging effects of the loss of material

and cracking for stainless steel components in a treated water environment in accordance with

the GALL Report.

3.4.2.3.1 Main Feedwater System

Staff Evaluation

The staff reviewed the AMR of the main feedwater system component, material, environment,

AERM combinations not addressed in the GALL Report. These combinations use notes F

through J in LRA Table 3.4.2-1. The staff also reviewed those combinations in Table 3.4.2-1

with notes A through E, which included emerging issues (i.e. ISG items). The staff verified 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 they adequately describe the AMPs.

Aging Effects

Table 2.3.4-1 of the LRA lists individual system components within the scope of license renewal

that are subject to an AMR. The component types that do not rely on the GALL Report for AMR

include bolting, piping, and valves.

For these component types, the applicant identified the materials, environments, and AERMs

specified as follows:

* . Carbon steel bolting in air (external) environments is subject to a loss of material and a

loss of mechanical closure integrity.

* Stainless steel bolting in air (external) environments is subject to a loss of mechanical.

closure integrity.

* Stainless steel components in treated water (greater than 132 'C (270 'F)) (internal)

environments are subject to a loss of material and to cracking. -

* .Stainless steel components in air (external) environments experience no aging effects.

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During its review, the staff determined that it required additional information to complete its

review.

RAI 3.4-2

Table 3.4-1, Item 1, of the LRA identifies the applicant's aging management approach for

cumulative fatigue damage of piping and fittings in the main feedwater line, the steamline, and

AFW piping. In the "Discussion" column for this item, the LRA states, "See Section 4.3 (of the

LRA]."

The applicant stated in Section 4.3 of the LRA that, based on the screening criteria, it

determined that some piping components in the main feedwater system exceed the screening criteria. The applicant evaluated the piping components that exceed the screening criteria for

their potential to surpass 7000 thermal cycles in 60 years of plant operation. The applicant determined that none of the piping components in the steam and power conversion system will

exceed 7000 cycles during the period of extended operation.

In RAI 3.4-2, the staff requested the applicant to provide the highest estimated number of

thermal cycles, as well as the basis for derivation for each component type identified in Table

3.4.2-1 of the LRA. The staff evaluates the applicant's response in Section 3.4.2.3 of this SER.

In its response to the RAI, the applicant stated that it did not account for unanticipated

transients in its methodology, and that if they occur, they are identified and evaluated for impact

on design thermal and loading cycles through the Corrective Action Program.

RAI 3.4-5

The applicant did not identify any aging effect for stainless steel tube and tube fittings or valves

(body only) in the reactor building environment. In RAI 3.4-5, the staff asked the applicant to

justify this omission. If insignificant concentration of contaminants comprised part of the

justification, the applicant was asked to provide the acceptance criterion and the

verification/inspection activities on susceptible locations to justify the position. Section 3.4.2.3

of this SER evaluates the applicant's response.

The staff finds the applicant's response reasonable and acceptable because the applicant provided the specific environments to which the stainless steel components are exposed. The

staff is satisfied that loss of material due to pitting and crevice corrosion of stainless steel

components under these conditions is not likely to occur.

RAI 3.4-10

Table 3.4.2-1 of the LRA identifies the loss of material and cracking as an aging effect for

various stainless steel components in treated water and steam environments. The applicant credited the Water Chemistry Control Program to manage this aging effect. Stainless steels

are susceptible to the loss of material in this type of environment, and the GALL Report

recommends that, for the loss of material due to pitting and crevice corrosion, the effectiveness

of the Water Chemistry Control Program should be verified to ensure that significant degradation is not occurring. In RAI 3.4-1 0, the staff requested the applicant to confirm that the

One-Time Inspection Program discussed in Appendix B to the LRA will verify the effectiveness

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of the Water Chemistry Control Program for various stainless steel components in treated water

and steam environments.

The staff discusses the applicant's response in Section 3.4.2.3 of this SER. The staff finds the

applicant's response'reasonable and acceptable because the applicant clarified how the

Chemistry One-Time Inspection Program will verify the effectiveness of the Water Chemistry

Control Program in managing-the aging effects of the loss of material and cracking for stainless

steel components in a treated water environment, in accordance with the GALL Report.

On the basis of its review of the information in the LRA and additional information included in

the applicant's response to the above RAls, the staff finds that the aging effects of the steam

and power conversion system component types that are not addressed in the GALL Report, as

well as the specific component types that are within the scope of 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 identified the

appropriate aging effects for the materials and environments associated with the above

components in the steam and power conversion system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above component

types, 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.

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 Program (B.1.2)

* Flow-Accelerated Corrosion Program (B.1.12)

* System Walkdown Program (B.1.38)

* Water Chemistry Control Program (B.1.40)

The staff reviews these AMPs in detail in Sections 3.0.3.3.2, 3.0.3.1, 3.0.3.3.14, and 3.0.3.3.16

of this SER, respectively.

In the LRA, the applicant stated that it did not identify any aging effects for stainless steel

components exposed to air, including piping 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, indoor, or

air-conditioned enclosure or room). Wrought austenitic stainless steels and CASS are not

susceptible to significant general corrosion that would affect the intended functions of

components. Therefore, the staff concludes that there' are no AERMs for metal in a dry air

environment.

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In the LRA, the applicant stated that it manages cracking and the loss of material for stainless

steel components exposed to an internal environment of treated water greater than 132 OC (270

OF) using the Water Chemistry Control-Primary and Secondary Water Program, with

enhancements. The staff documents its evaluation of this AMP in Section 3.0.3.2.15 of this

SER. The GALL Report, Section VIII.D.1.1-c, recommends that the AMP be augmented by

verifying the effectiveness of the Water. Chemistry Control Program. Table 3.4.1, Item 3.4.1-2,

of the LRA and LRA Section 3.4.2.2.2 both identify the Wall Thinning Monitoring Program as

the verification program that will supplement the Water Chemistry Control Programs.

In the LRA, the applicant stated that the Water Chemistry Control-Chemistry One-Time

Inspection Program is a new program that is consistent with GALL AMP XI.M32, but of a more

limited scope. The staff documents its evaluation of this AMP in Section 3.0.3.3.17 of this SER.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant identified the appropriate AMPs for managing the aging effects of the main feedwater

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 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 it will maintain the intended

functions 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 for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.4.2.3.2 Main Steam System

Staff Evaluation

The staff reviewed the AMR of the main steam system component, material, environment,

AERM combinations that are not addressed in the GALL Report. These combinations use

notes F through J in LRA Table 3.4.2-1. The staff also reviewed those combinations in Table

3.4.2-2 with notes A through E, which include emerging issues (i.e. ISG items). The staff *

verified that the applicant identified all applicable AERMs and credited the appropriate AMPs for

managing the AERMs. The staff also reviewed the applicable UFSAR Supplements for the

AMPs to ensure that they adequately describe the AMPs.

Aging Effects

Table 2.3.4-2 of the LRA lists individual system components within the scope of license renewal

that are subject to an AMR. The component types that do not rely on the GALL Report for AMR

include bolting, manifold piping, orifices, piping, tubing, and valves.

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For these component types, the applicant identified the materials, environments, and AERMs

specified as follows:

* Carbon steel bolting in air (external) environments is subject to a loss of material and a

loss of mechanical closure integrity.

* Stainless steel bolting in air (external) environments is subject to a loss of mechanical

closure integrity.

* Stainless steel components in steam (greater than 132 'C (270 'F) (internal) and treated

water (greater than 132 0C (270 'F) (internal) environments are subject to a loss of

material and cracking.

* Stainless steel components in air (external) environments experience no aging effects.

During its review, the staff determined that it required additional information to complete its

evaluation.

Table 3.4-1, Item 1, of the LRA identifies the applicant's aging management approach for

cumulative fatigue damage of piping and fittings in the main feedwater line, the steamline, and

AFW piping. In the "Discussion" column for this item, the LRA states, "See Section 4.3 [of the

LRA]."

The applicant stated in Section 4.3 of the LRA that, based on the screening criteria, it

determined that some piping components in the main steam system exceed the screening

criteria. The applicant evaluated the piping components that exceed the screening criteria for

their potential to surpass 7000 thermal cycles in 60 years of plant operation. Main steam

system thermal cycles anticipated over 60 years correspond to heatup and cooldown cycles, for

which CNP is restricted to 200 cycles. Therefore, main steam piping and valves will not

experience 7000 cycles during the period of extended operation.

RAI 3.4-10

Table 3.4.2-2 of the LRA identifies the loss of material and cracking as an aging effect for

various stainless steel components in treated water and steam environments. The applicant

credited the Water Chemistry Control Program to manage this aging effect. -Stainless steels

are susceptible to the loss of material in this type of environment, and the GALL Report

recommends that, for the loss of material due to pitting and crevice corrosion, the effectiveness

of the Water Chemistry Control Program should be verified to ensure that significant

degradation is not occurring. In RAI 3.4-10, the staff requested the applicant to confirm that the

One-Time Inspection Program discussed in Appendix B to the LRA will verify the effectiveness

of the Water Chemistry Control Program for various stainless steel components in treated water

and steam environments.

Section 3.4.2.3 of this SER discusses the applicant's response and the resolution of the staff's

concerns. The staff finds the applicant's response reasonable and acceptable because the

applicant clarified how the Chemistry One-Time Inspection Program will verify the effectiveness

of the Chemistry Control Program in managing the aging effects of the loss of material and

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cracking for stainless steel components in a treated water environment, in accordance with the

GALL Report.

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 3.4-10, the staff finds that the applicant has identified the 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.

Aging Management Programs

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 steam system component groups.

The applicant stated in the LRA that it identified no aging effects for stainless steel components exposed to air, including manifold (piping), piping, 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, indoor, or

air-conditioned enclosure or room). Wrought austenitic stainless steels and CASS are not

susceptible to significant general corrosion that would affect the intended function of

components. Therefore, the staff concludes that there are no AERMs for metal in a dry air

environment.

In the LRA, the applicant stated that it uses the Water Chemistry Control-Primary and

Secondary Water Program, with enhancements, to manage cracking and the loss of material

for stainless steel manifold, piping, tubing, and valves exposed to internal environments of

treated water greater than 132 0C (270 0F) and steam greater than 132 0C (270 OF). The staff

documents its evaluation of this AMP in Section 3.0.3.2.15 of this SER. The staff noted that the

GALL Report does not discuss similar component, material, and environment combinations.

However, the aging effects of cracking and loss of material for the main steam system stainless

steel components exposed to internal environments of treated water greater than 132 OC (270 OF) and steam greater than 132 0

C (270 0F) are consistent with industry operating experience. The staff finds that the appropriate aging effects were identified and are adequately managed and, therefore, are acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, as well as 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 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 for managing aging in

these components, as required by 10 CFR 54.21 (d).

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3.4.2.3.3 Auxiliary Feedwater System

Staff Evaluation

The staff reviewed the AMR of the AFW system component, material, environment, and 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 for those for which past precedents exist. The staff also

reviewed those combinations in Table 3.4.2-3 with notes A through E, for which emerging

issues were identified. The staff verified that the applicant identified all applicable AERMs and

credited the appropriate AMPs for managing the AERMs. The staff also reviewed the'

applicable UFSAR Supplements for the AMPs to ensure that they adequately describe the

AMPs.

Aging Effects

Table 2.3.4-3 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 bolting, fittings, heat exchanger (tubes),- orifices, piping, manifold piping; sight glass,

tanks, tubing, turbine casing and valves.

For these component types, the applicant identified the materials, environments, and AERMs

specified as follows:

* Carbon steel bolting in air (external) environments is subject to a loss of material and a

loss of mechanical closure integrity.

* Carbon steel components in steam (greater than 132 0C (270 OF)) (internal) and treated

water (internal) environments are subject to a loss of material and cracking fatigue.

* Stainless steel bolting in air (external) environments is subject to -a loss of mechanical

closure integrity.

* Stainless steel components in a steam (greater than 132 0C (270 OF)) (internal)

environment are subject to a loss of material, cracking - fatigue, and cracking.

* Stainless steel components in a treated water (internal) environment are subject to a

loss of material.

* Stainless steel components in air (internal and external), outdoor air (external), and

concrete (external) environments experience no aging effects.

* Copper alloy components in lubricating oil (internal) and treated water (internal)

environments are subject to fouling and a loss of material.

* Copper alloy components in air (external) and outdoor air (external) environments

experience no aging effects.

* Elastomer components in air (external) and treated water (internal) environments are

subject to cracking and change in material properties.

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L

Glass components in air (external) and lubricating oil (internal) environments experience

no aging effects.

During its review, the staff determined that it required additional information to complete its

evaluation.

RAI 3.4-1

Table 3.4.2-3 of the LRA identifies no aging effects for copper alloy in an outside environment

in the AFW system. The outside environment is generally defined as follows:

An environment where components are exposed to direct sunlight, precipitation,

and freezing conditions. The outside environment also conservatively includes

components located in sheltered areas where the component is beneath some

type of roof structure or outdoor enclosure (such as a valve box) but is otherwise

open to the ambient environment.

The GALL Report does not identify copper alloy components for this environment. However,

the GALL Report recommends aging management for the loss of material due to general

corrosion on the external surfaces of carbon (alloy) steel components exposed to operating

temperatures less than 100 0C (212 OF). Such corrosion may result from air, moisture, or

humidity. In RAI 3.4-1, the staff requested the applicant to provide a program to manage

corrosion on the external surface of copper alloy components in an outside environment, or to

justify not managing this aging effect.

In its response, the applicant stated the following:

The copper alloy components exposed to outdoor air in LRA Table 3.4.2-3 are

instrument tubing, fittings, and valves off the condensate storage tank. Unlike

carbon steel materials which are not corrosion resistant, copper alloys are highly

resistant to general corrosion in an external air environment. These copper alloy

components are sheltered (either located inside or insulated) and are not directly

exposed to the atmosphere. These components are not expected to be exposed

to significant moisture or contaminants (such as those deposited as a result of

alternating wetting and drying); therefore, loss of material due to pitting, crevice

corrosion, or selective leaching is not an aging effect requiring management.

The staff finds the applicant's response satisfactory and acceptable because it provides an

adequate justification for not managing the aging effect of corrosion on the external surface of

copper alloy components.

RAl 3.4-3

The applicant stated in Table 3.4.2-3 of the LRA that stainless steel tanks in an external

concrete environment have no AERms and that the GALL Report contains no AMP for this

component and material in such an environment. In RAI 3.4-3, the staff requested the applicant

identify the specific tanks in the AFW system and discuss how it assures the integrity of welds

and wall thickness in inaccessible locations in the tank, including method and frequency of

inspections, as well as the basis for this approach.

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The applicant identified the stainless steel tank exposed to a concrete (external) environment

as the CST (TK-32), which is depicted on license renewal drawings LRA-1 -51 06A and

LRA-2-5106A. The applicant also stated the following:

The tank base is in contact with the concrete pad. The concrete pads are

constructed in accordance with ACI 318-63, which results in high-quality

concrete free of contamination. Therefore, loss of material is not an aging effect

requiring management due to the inherent corrosion resistance of stainless steel,

the high alkalinity of concrete, and the lack of contamination. Since there are no

aging effects requiring management for this external stainless steel surface,

periodic thickness measurements are not required.

The staff finds the applicant's response reasonable and acceptable because it adequately

justifies that AERMs are not likely to occur at the bottom of the stainless steel tank.

RAI 3.4-6.

The applicant identified no applicable aging effect for carbon steel components in an embedded

environment. If this environment involves concrete, corrosion of carbon steel components'

embedded in concrete through carbonation is a commonly known degradation process. In RAI

3.4-6 the staff requested that the applicant explain this omission. In its response the applicant

stated the following:

During scoping and screening of mechanical portions of the steam and power

conversion systems, no carbon steel components in an embedded environment

were identified as subject to aging management review. LRA Table 3.4.1, Items

3.4.1-11 and 3.4.1-12, document this result.

Because the steam and power conversion system does not include any no carbon steel

components in an embedded environment, the staff considers the RAI issue resolved.

RAI 3.4-7

The applicant stated in Table 3.4.2-3 of the LRA that it will use the Oil Analysis and Water

Chemistry Control Programs to manage fouling in heat exchangers with copper alloy tubes in

lubricating-oil and treated-water environments to assure the heat transfer capability. In RAI

3.4-7, the staff requested the applicant to explain how these two AMPs will manage fouling and

assure adequate heat transfer. The staff also requested that the applicant address whether it

would perform any cleaning, visual inspections, and thermal performance testing, including the

frequency of such inspections and tests and the basis for this approach.

In its response, the applicant stated the following:

The heat exchangers in LRA Table 3.4.2-3 are the turbine-driven AFW pump

turbine bearing lube oil cooler (HE-70) and governor oil cooler (HE-71), which

are depicted on license renewal drawings LRA-1-5106A at locations L3 and M2

and LRA-2-5106A at locations D2 and E2. As part of the Primary and Secondary

Water Chemistry Control Program, water quality and level of contaminants in the

secondary plant water (i.e., AFW) are monitored and maintained within the

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specifications of EPRI TR-102134, Revision 5. The Oil Analysis Program

monitors and controls abnormal levels of contaminants (primarily water and

particulates), thereby preserving an environment that is not conducive to fouling. By maintaining proper water chemistry and oil quality, contaminants within these

fluids are minimized such that fouling that could result in the loss of heat transfer

function is prevented. Visual inspections and thermal performance testing are

not included in these programs. However, the Chemistry One-Time Inspection

Program, as described in LRA Section B.1.41, includes inspections to verify effectiveness of the chemistry control programs. Based on plant operating experience, there is reasonable assurance that the Oil Analysis Program and the

Primary and Secondary Water Chemistry Control Program will continue to

adequately manage fouling associated with components exposed to lubricating oil and secondary plant water so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation.

The staff finds the applicant's response reasonable and acceptable because the applicant provided a satisfactory explanation of how it will manage the aging effect of fouling in the

copper alloy tubes of the heat exchangers. Therefore, the staff considers the issues related to

this RAI to be resolved.

RAI 3.4-8

Table 3.4.2-3 of the LRA identifies loss of material and fouling for copper alloy heat exchanger tubes in a treated water environment. The applicant credited the Water Chemistry Control

Program to manage this aging effect. The GALL Report does not identify this material for this

component, but it recommends the Water Chemistry Control Program and a one-time

inspection to manage the loss of material for carbon/alloy steel components in a treated water

environment. Table 3.4.2-3 of the LRA does not identify a one-time inspection to verify the

effectiveness of the Water Chemistry Control Program. However, Appendix B to the LRA

(Section B.1.41) discusses a new plant-specific one-time inspection program. In RAI 3.4-8, the

staff requested the applicant to clarify that this program will include inspections and

examinations to verify the effectiveness of the Water Chemistry Control Program to manage the

loss of material and fouling for copper alloy heat exchanger tubes in a treated water

environment.

In its response, the applicant stated the following:

The heat exchangers in LRA Table 3.4.2-3 are the turbine-driven AFW pump

turbine bearing lube oil cooler (HE-70) and the governor oil cooler (HE-71),

which are depicted on license renewal drawings LRA-1 -51 06A at locations L3

and M2 and LRA-2-5106A at locations D2 and E2. Effectiveness of the water

chemistry control programs will be verified by the Chemistry One-Time

Inspection Program as described in LRA Section B.1.41. Inspections and

examinations performed under the Chemistry One-Time Inspection Program will

verify the effectiveness of the Primary and Secondary Water Chemistry Control

Program in managing loss of material and fouling for copper alloy heat

exchanger tubes in a treated water environment.

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The staff finds the applicant's response reasonable and acceptable because the applicant

confirmed that the Chemistry One-Time Inspection Program will verify the effectiveness of the

Water Chemistry Control Program in managing the loss of material and fouling for copper alloy'

tubes in a treated water environment. Therefore, the staff considers the issues related to this

RAI to be resolved.

RAI 3.4-9

Table 3.4.2-3 of the LRA states that the Preventive Maintenance Program will manage the

change in material properties and cracking of elastomeric material of tanks in a treated water

environment. However, the Preventive Maintenance Program in Appendix B to the LRA-does

not discuss the aging management of pressure-retaining elastomeric tanks in a treated water

environment. In RAI 3.4-9 the staff requested the applicant describe how it will manage the

change in material properties and cracking in tanks, including its inspection methods for

inaccessible locations and the frequency of inspections, as well as its acceptance criteria and

the basis thereof.

In its response to RAI 3.4-9, the applicant stated the following:

The elastomer material identified for the component type 'Tank' listing in

LRA Table 3.4.2-3 refers to the CST floating head seals. The floating head

seals and associated support posts were included in the aging management

review because the failure of these seals could cause flow blockage. As stated

in LRA Section B.1.25, the Preventive Maintenance Program will be enhanced

prior to the period of extended operation to include visual inspection and

replacement, as needed, of these elastomer floating head seals. Inaccessible

locations will be exposed to the same environments (i.e., air and treated water)

as the accessible locations that will be subject to the visual inspections;

therefore, the condition of the accessible surfaces of the elastomer seal would

be representative of the inaccessible locations. The seal inspection frequency

will be established based on industry and plant-specific operating experience and

manufacturer's recommendations. Acceptance criteria will be defined by specific

inspection and testing procedures based on industry and plant-specific operating

experience and manufacturer's recommendations.

The staff finds the applicant's response reasonable and acceptable because the applicant

provided a satisfactory description of how it will manage the aging effects of change in material

properties and cracking for elastomeric materials in a treated water environment. Therefore,

the staff considers the issues related to this RAI to be resolved.

On the basis of its review of the information 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 AFW

system component types not addressed by the GALL Report are consistent with industry

experience for these combinations of materials and environments. L 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 AFW

system. -

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Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above component

types, 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.

Table 3.4.2-3 of the LRA identifies the following AMPs for managing the aging effects described

above for the AFW system:

* Bolting and Torquing Activities Program

* Heat Exchanger Monitoring Program

* Oil Analysis Program

* Preventive Maintenance Program

* System Walkdown Program

* Water Chemistry Control Program

* Wall Thinning Monitoring Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.2, 3.0.3.3.5, 3.0.3.3.8,

3.0.3.3.10, 3.0.3.3.14, 3.0.3.2.15 and 3.0.3.3.15 of this SER, respectively.

The applicant stated in the LRA that it identified no aging effects for the copper alloy fittings,

manifold, tubing, and valves exposed to air, as well as for fittings, tubing, and valves in outdoor

air. The applicant identified no aging effects for stainless steel fittings, manifold, orifices,

tubing, and valves exposed to air, as well as for fittings, piping, tanks, tubing, and valves in

outdoor air. 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). Wrought austenitic stainless steels are not susceptible to

significant general corrosion that would affect the intended function of the components.

Therefore, the staff concludes that metal in a dry air environment has no AERMs.

In the LRA, the applicant stated that it manages cracking and the loss of material for stainless

steel fittings, tubing, and valves exposed to an internal environment of steam greater than

132 'C (270 'F) using the Water Chemistry Control - Primary and Secondary Water Chemistry

Control Program, with enhancements. The staff documents its evaluation of this AMP in

Section 3.0.3.2.15 of this SER. The GALL Report does not discuss similar component,

material, and environment combinations. The aging effects of cracking and the loss of material

for the AFW system's stainless steel components exposed to an internal environment of steam

greater than 132 0C (270 'F) are consistent with industry operating experience. The staff finds

that the applicant identified and adequately manages the appropriate aging effects. The staff

finds this to be acceptable.

In the LRA, the applicant stated that it manages fouling and the loss of material for copper alloy

heat exchanger tubes exposed to an external environment of lubricating oil using the Oil

analysis Program. The staff documents its evaluation of this program in Section 3.0.3.3.8 of

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this SER. The GALL Report does not discuss similar component, material, and environment

combinations. On the basis that the applicant's Oil Analysis Prograimi maintains oil systems free

of contaminants (primarily water and particulates), the staff finds that this program adequately

manages cracking and the loss of material for components exposed to lubricating oil.

In the LRA, the applicant stated that the sight glass component type (glass) in an external

environment of air or an internal environment of lubricating oil has no aging effects. The GALL

Report does not discuss similar component, material, and environment combinations. On the

basis that no aging effects require management for these components, the staff finds the

absence of an AMP for glass to be acceptable.

In the LRA, the applicant stated that it manages cracking and change in material properties of

tank elastomer exposed to an external environment of air and an internal environment of

treated water using the Preventive Maintenance Program (CNP AMP B.1.25), with

enhancements. The applicant stated that the program enhancement will rely upon visual

inspection to detect cracking and change in material properties of the AFW system elastomer

CST's floating head seals. The staff documents its evaluation of this AMP in Section 3.0.3.3.10

of this SER.

The GALL Report does not discuss similar component, material, and environment

combinations. The staff found documentation only of visual inspection, which is an acceptable

method for detecting cracking. The staff asked the applicant to clarify how it intends to detect

changes in material properties. The staff asked the applicant, in RAI 3.4-9, to describe how it

will manage the change in material properties and cracking of elastomeric materials in tanks,

including its inspection methods for inaccessible locations, frequency of inspections,

acceptance criteria, and the basis for its approach. The staff evaluated and accepted the

applicant's response to this RAI as described above.

In the LRA, the applicant stated that it manages the loss of material from copper alloy valves in

treated water using the Water Chemistry Control Program. On the basis that this is consistent

with the management of similar items identified in the GALL Report, the staff finds it to be

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 AFW 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, as well as the AMPs credited with managing the aging effects, for the AFW

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).

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l.

The staff also reviewed the applicable UFSAR Supplement program descriptions and concludes

that the UFSAR Supplement adequately describe the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.4.2.3.4 Blowdown System

Staff Evaluation

The staff reviewed the AMR of the blowdown system component, material, environment, and

AERM combinations that are not addressed in the GALL Report. These combinations use

notes F through J in LRA Table 3.4.2-4, except for those for which past precedents exist. The

staff also reviewed those combinations in Table 3.4.2-4 with notes A through E, for which

emerging issues were identified. The staff verified that the applicant identified all applicable

AERMs and credited the appropriate AMPs to manage the AERMs. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that they adequately describe the

AMPs.

Aging Effects

Table 2.3.4-4 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 an AMR

include bolting, orifices, piping, tubing, and valves.

For these component types, the applicant identified the materials, environments, and AERMs

specified as follows:

* Carbon steel components in air (external) environments are subject to a loss of material

and a loss of mechanical closure integrity.

* Carbon steel components subjected to treated water (greater than 132 0C (270 OF))

(internal) environments are subject to cracking fatigue.

* Stainless steel bolting in air (external) environments is subject to a loss of mechanical

closure integrity.

* Stainless steel components in treated water (greater than 132 0 (270 OF)) (internal)

environment are subject to a loss of material and cracking.

During its review, the staff determined that it required additional information to complete its

evaluation. The following provides the staff's evaluation and resolution of its concerns.

RAI 3.4-2

The applicant determined that none of the piping components in the steam and power

conversion system will exceed 7000 cycles during the period of extended operation. In RAI

3.4-2, the staff requested the applicant provide the highest estimated number of thermal cycles,

as well as the basis for derivation for each component type identified in Table 3.2.4-4 of the

LRA for the blowdown systems.

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In its response to the RAI, the applicant stated that the steam generator blowdown (SGBD)

system is placed in service primarily during startup to obtain the required water chemistry for

normal operation. The plant is restricted to 200 heatups and cooldowns; therefore, this system

will not exceed 200 equivalent full-temperature cycles. After startup, the SGBD system is used

when corrections are required for secondary water chemistry. Sample lines connected to the

SGBD system are in service continuously when blowdown is being exercised. For the period of

extended operation, the systemn is not expected to exceed 5000'full-temperature equivalent

cycles to correct secondary water chemistry, during normal operation (assuming two secondary

water chemistry corrections per week for 60 years, with an 80-percent capacity factor).

Therefore, the SGBD system will not experience 7000 thermal cycles during the period of

extended operation. The staff finds the applicant's response reasonable and acceptable

because it clarifies the basis for derivation of the thermal cycles for the blowdown system.

Section 3.4.2.3 of this SER discusses other staff concerns brought forth in RAI 3.4-2.

Table 3.4.2-4.of the LRA identifies the loss of material and cracking as aging effects for various

stainless steel components in treated water and steam environments. In RAI 3.4-10the staff

requested the applicant confirm that the One-Time Inspection Program discussed in Appendix

B to the LRA will verify the effectiveness of the Water Chemistry Control Program for various

stainless steel components in treated water and steam environments.

In its response the applicant stated, 'For steam and power conversion systems stainless steel

components, NUREG-1 801 only recommends augmentation of the water chemistry program for

the CST and heat exchanger tubes."

The staff finds the applicant's response reasonable and acceptable because the applicant

clarified how the Chemistry One-Time Inspection Program will verify the effectiveness of the

Water Chemistry Control Program in managing the aging effects of the loss of material and

cracking for stainless steel components in a treated water environment, which is in accordance

with the GALL Report. The staff discusses other concerns brought up in RAI 3.4-10 in Section

3.4.2.3 of this SER.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above component

types, 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.

Table 3.4.2-4 of the LRA identifies the following'AMPs for managing the aging effects described

above for the blowdown system:

* . Bolting and Torquing Activities Program

* System Walkdown Program

* Water Chemistry Control Program

* Flow-Accelerated Corrosion Program

* System Testing Program

The staff's detailed review of these AMPs appears in Sections 3.0.3.3.2, 3.0.3.3.14, 3.0.3.2.15,

3.0.3.1 and 3.0.3.3.13 of this SER, respectively.

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I

The applicant stated that it did not identify any aging effects for stainless steel components

exposed to air, including orifices, piping, 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, indoor, or

air-conditioned enclosure or room). Therefore, the staff concludes that metal in a dry air

environment has no AERMs.

In the LRA, the applicant stated that it manages cracking and the loss of material for stainless

steel orifices, piping, tubing, and valve exposed to an internal environment of treated water

greater than 132 0C (270 OF) using the Water Chemistry Control-Primary and Secondary

Water Chemistry Control Program, with enhancements. The staff documents its evaluation of

this AMP in Section 3.0.3.2.15 of this SER. The GALL Report does not discuss similar

component, material, and environment combinations. The aging effects of cracking and loss of

material for the blowdown system's stainless steel components exposed to internal

environments of treated water greater than 132 0C (270 OF) are consistent with industry

operating experience. The staff finds that the applicant identified and adequately manages the

appropriate aging effects. The staff finds this to be 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 the appropriate AMPs for managing the aging effects of the blowdown 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, as well as the AMPs credited with managing the aging effects, for the blowdown

system components that are not addressed by the GALL Report, so that the intended functions

will be 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).

3.4.3 Conclusion

The staff concludes that the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the main feedwater, main steam, AFW, and

blowdown system components that are within the scope of license renewal and subject to an

AMR so that the intended functions will be consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Li

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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 and commodity groups associated with the following

structures:

* containment

* auxiliary building

* -turbine building and screenhouse

* yard structures

* structural 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 2.4-5 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, "Summary of Aging Management Programs for Structures and Component

Supports Evaluated in Chapters II and IlIl 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

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 Evaluation

The staff reviewed Section 3.5 of the LRA to understand the applicant's review process and to

determine whether the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the structures and component supports that are

within the scope of license renewal and subject to an AMR, so that the intended functions will

be 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 verify that

the material presented in the LRA is applicable and that the applicant identified the appropriate

GALL AMRs. Section 3.5.2.1 of this SER summarizes the staff's audit and review findings .

The staff also audited those AMRs that are consistent with the GALL Report and for which

further evaluation is recommended. The staff verified that the applicant's further evaluations

were consistent with the acceptance'criteria in Section 3.5.3.2 of the SRP-LR. Section 3.5.2.2

of this SER summarizes the staff's audit and review findings.

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

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aging effects and whether the aging effects listed were appropriate for the combination of

materials and environments specified. The staff documents its review findings in Section

3.5.2.3 of this SER.

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

structures and component supports.

Table 3.5-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.5 that are addressed in the GALL Report.

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

GALL Report

-Component -Agin EffeVt AMP - Ing GALL.' - 'AMP in IRA Staff Evaluation

'Group'.- '-Mechanismr- . i: 'Report ';

Penetration Cumulative fatigue TLAA evaluated in TLAA Consistent with

sleeves, damage (CLB fatigue accordance with GALL, which

penetration analysis exists) 10 CFR 54.21(c) recommends

bellows, and further evaluation

dissimilar metal (See Sections

welds (Item 3.5.2.2.1 and 4.6)

Number 3.5.1-1)

Penetration Crack initiation and Containment ISI Containment Consistent with

sleeves, bellows, growth due to SCC and containment Leakage Rate GALL, which

and dissimilar leak rate test Testing Program recommends

metal welds (Item (B.1.8); Inservice further evaluation

Number 3.5.1-2) Inspection-ASME (See Section

Section Xi, 3.5.2.2.1)

Subsection IWE

Program (B.1.15)

Penetration Loss of material due to Containment ISI Containment Consistent with

sleeves, bellows, corrosion and containment Leakage Rate GALL, which

and dissimilar leak rate test Testing Program recommends no

metal welds (Item (B.1.8); Inservice further evaluation

Number 3.5.1-3) Inspection-ASME (See Section

Section Xl, 3.5.2.1)

Subsection IWE

Program (B.1.15)

Personnel airlock Loss of material due to Containment ISI Containment Consistent with

and equipment corrosion and containment Leakage Rate GALL, which

hatch (Item leak rate test Testing Program recommends no

Number 3.5.1-4) (B.1.8); Inservice further evaluation

Inspection-ASME (See Section

Section Xl, 3.5.2.1)

Subsection IWE

Program (B.1.15)

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-Component ' - Aging Effect. AMP in GALL" AMP in LRA Staff Evaluation

-Group* ' Mechanism - Report ' - - -

Personnel airlock Loss of leak tightness Containment leak Containment Consistent with

and equipment in closed position due rate test and plant Leakage Rate GALL, which

hatch (Item to mechanical wear of technical Testing Program recommends no

Number 3.5.1-5) locks, hinges, and specifications (B.1.8); Inservice further evaluation

closure mechanisms Inspection-ASME (See Section

Section Xl, 3.5.2.1)

Subsection IWE

Program (B.1.15);

CNP Technical

Specification :

Seals, gaskets, Loss of sealant and Containment ISI Containment Consistent with

and moisture leakage through and containment Leakage Rate GALL, which

barriers (Item containment due to leak rate test Testing Program recommends no

Number 3.5.1-6) deterioration of joint (B.1.8); Inservice further evaluation

seals, gaskets, and Inspection-ASME (See Section

moisture barriers Section Xl, - 3.5.2.1)

Subsection IWE

Program (B.1.15)

Concrete Aging of accessible Containment ISI Inservice Consistent with

elements- and inaccessible Inspection-ASME GALL, which

foundation, dome, concrete areas due to Section Xl, recommends

and wall (Item- leaching of calcium Subsection IWL further evaluation

Number 3.5.1-7) hydroxide, aggressive Program (8.1.17); (See Section

chemical attack, and Structures 3.5.2.2.1)

corrosion of embedded Monitoring Program

steel (B.1.32)

Concrete Cracks, distortion, and Structures Structures Consistent with

elements- increases in monitoring Monitoring- GALL, which

foundation (Item component stress level Structures recommends no

Number 3.5.1-8) due to settlement Monitoring Program further evaluation

(B.1.32) (See Section

L_ 3.5.2.2.1)

Concrete . Reduction in Structures Structures Consistent with

elements- foundation strength monitoring Monitoring- GALL, which

foundation (Item due to erosion of Structures recommends no

Number 3.5.1-9) porous concrete Monitoring Program further evaluation

subfoundation - - (8.1.32); Inservice (See Section

Inspection-ASME 3.5.2.2.1)

Section Xl,

Subsection IWL

. . Program (B.1.17)

Concrete Reduction of strength- Plant specific Structures Consistent with

elements- and modulus due to Monitoring- GALL, which

foundation, dome, elevated temperature - Structures recommends

and wall (Item Monitoring Program further evaluation

Number 3.5.1-10) (B.1.32); Inservice (See Section

Inspection-ASME 3.5.2.2.1)

Section Xl,

Subsection IWL

Program (B.1.17)

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I I

Component '- i Aging Effect, AMP in:GALL- ' AMP in LRA Staff Evaluation

Group'- :- Mechanism Report: -. ,,,,,;,,_ ____, __,. _

Prestressed Loss of prestress due TLAA evaluated in Not Applicable Consistent with

containment- to relaxation, accordance with GALL, which

tendons and shrinkage, creep, and 10 CFR 54.21(c) recommends

anchorage elevated temperature further evaluation

components (Item (See Sections

Number3.5.1-1 1) 3.5.2.2.1 and 4.5)

Steel elements- Loss of material due to Containment ISI Structures Consistent with

liner plate and corrosion in accessible and containment Monitoring- GALL, which

containment shell and inaccessible areas leak rate test Structures recommends

(Item Number Monitoring Program further evaluation

3.5.1-12) (B.1.32); Inservice (See Section

Inspection-ASME 3.5.2.2.1)

Section Xl,

Subsection IWE

-_ Program (B.1.17)

Steel elements- Loss of material due to Protective coating Not Applicable Consistent with

protected by corrosion in accessible monitoring and GALL, which

coating (Item areas only maintenance recommends no

Number 3.5.1-14) further evaluation

(See Section

3.5.2.1)

Prestressed Loss of material due to Containment ISI Not Applicable Consistent with

containment- corrosion of GALL, which

tendons and prestressing tendons recommends no

anchorage and anchorage further evaluation

components (Item components (See Section

Number 3.5.1-15) 3.5.2.1)

Concrete Scaling, cracking, and Containment ISI Structures Consistent with

elements- spalling due to freeze- Monitoring- GALL, which

foundation, dome, thaw; expansion and Structures recommends no

and wall (Item cracking due to Monitoring Program further evaluation

Number 3.5.1-16) reaction with aggregate (B.1.32); Inservice (See Section

Inspection-ASME 3.5.2.2.2)

Section Xl,

Subsection IWL

._ Program (B.1.17)

All groups except All types of aging Structures Structures Consistent with

Group 6- effects monitoring Monitoring- GALL, which

accessible Structures recommends no

interior/exterior Monitoring Program further evaluation

concrete steel (B.1.32) (See Section

components (Item 3.5.2.2.2)

Number 3.5.1-20)

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Component A Effect AM in GALL - AMP in LRA: Staff Evaluation'

Group. - Mechanism a 'Report ' - . . - . - __-

Groups 1-3, 5, Aging of inaccessible Plant specific', Not Applicable Consistent with

and 7-9- concrete areas due to GALL, which

inaccessible aggressive chemical - recommends

concrete attack; corrosion of further evaluation

components, embedded steel (See Section

such as exterior 3.5.2.2.2)

walls below grade . .

and foundation

(Item Number

3.5.1-21) ' . .

Group 6-all All types of aging - , Inspection of water- Structures Consistent with

accessible/ effects, including loss control structures Monitoring- GALL, which

inaccessible of material due to or FERC/U.S. Army Structures recommends no

concrete, steel, abrasion, cavitation, Corp of Engineers Monitoring Program further evaluation

and earthen and corrosion dam inspection and (B.1.32) (See Section

components (Item maintenance 3.5.2.1)

Number 3.5.1-22)

Group 5-liners Crack initiation and Water chemistry System Testing Consistent with

(Item Number growth due to SCC; and monitoring Program (B.1.37) GALL, which

3.5.1-23) . loss of material due to spent fuel pool . recommends no

crevice corrosion water level . further evaluation

(See Section

3.5.2.1)

Groups 1-3, 5, Cracking due to Masonry wall Structures . Consistent with

and 6-all restraint, shrinkage, Monitoring- GALL, which

masonry block -creep, and aggressive Masonry Wall recommends no

walls (Item environment Program (B.1.36) further evaluation

Number 3.5.1-24) . (See Section

._ ._ . 3.5.2.1)

Groups 1-3, 5, Cracks, distortion, and Structures Structures . Consistent with

and 7-9- increases in monitoring Monitoring- GALL, which

foundation (Item component stress level Structures recommends no

Number 3.5.1-25) due to settlement Monitoring Program further evaluation

(B.1.32) (See Section

._ _3.5.2.2.1)

Groups 1-3 and Reduction in Structures Structures Consistent with

5-9-foundation foundation strength monitoring Monitoring- GALL, which '

(Item Number due to erosion of Structures recommends no

3.5.1-26) porous concrete Monitoring Program further evaluation

subfoundation . . . (B.1.32) . (See Section

......._ 3.5.2.2.1)

Groups 1-5- - Reduction of strength Plant specific Structures Consistent with

concrete (Item and modulus due to Monitoring- GALL, which

Number 3.5.1-27) elevated temperature' Structures recommends

Monitoring Program further evaluation

(B.1.32) (See Section

._ ._ 3.5.2.2.1)

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I

Component Aging Effect) AMP in GALL- AMP in LRA Staff Evaluation

- Group -. Mechanism .. A...;. Report .... . . -

Groups 7-8- Crack initiation and Plant specific Not Applicable Consistent with

liners (item growth due to SCC; GALL, which

Number 3.5.1-28) loss of material due to recommends

crevice corrosion further evaluation

(See Section ._ 3.5.2.2.2)

All groups' Aging of component Structures Structures Consistent with

support supports monitoring Monitoring- GALL, which

members- Structures recommends no

anchor bolts, Monitoring Program further evaluation

concrete (B.1.32) (See Section

surrounding 3.5.2.2.3)

anchor bolts,

welds, grout pad,

bolted

connections, etc.

(Item Number

3.5.1-29)

Group B1.1, B1.2, Cumulative fatigue TLAA evaluated in TLAA Consistent with

and B1.3 support damage (CLB fatigue accordance with GALL, which

members- analysis exists) 10 CFR 54.21(c) recommends

anchor bolts and further evaluation

welds (Item (See Sections

Number 3.5.1-30) 3.5.2.2.3 and 4.3)

All groups' Loss",f material due to Boric acid corrosion Boric Acid Consistent with

support boric acid corrosion Corrosion GALL, which

members- Prevention recommends no

anchor bolts and Program (B.1.4) further evaluation

welds (Item (See Section

Number 3.5.1-31) 3.5.2.1)

Group B1.1, B1.2, Loss of material due to ISI Inservice Consistent with

and B1.3 support environmental Inspection-ASME GALL, which

members- corrosion; loss of Section Xl, recommends no

anchor bolts, mechanical function Subsection IWF further evaluation

welds, spring due to corrosion, Program (B.1.16) (See Section

hangers, guides, distortion, dirt, 3.5.2.1)

stops, and overload, etc.

vibration isolators

(Item Number

3.5.1-32)

Group B1.1- Crack initiation and Bolting integrity Inservice Consistent with

high-strength low- growth due to SCC Inspection-ASME GALL, which

alloy bolts (Item Section Xl, recommends no

Number 3.5.1-33) Subsection IWF further evaluation

Program (B.1.16); (See Section

Boric Acid 3.5.2.1)

Corrosion

Prevention

Program (B.1.4)

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The staff's review of the structures and component supports followed three separate

approaches. One approach, documented in Section 3.5.2.1 of this SER, involves the staff's

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review of the AMR results for components in the structures and commodities that the applicant

indicated are consistent with the GALL Report and do not require further evaluation. Another

approach, documented in Section 3.5.2.2 of this SER, involves the staff's review of the AMR

results for components in the structures and commodities 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 review of the AMR

results for components in the structures and commodities that the applicant indicated are not

consistent with the GALL Report or are not addressed in the GALL Report. The staff

documents its review of AMPs credited to manage or monitor aging effects of the structures

and component supports in Section 3.0.3 of this SER.

3.5.2.1 -Aging Management Evaluations That Are Consistent with the GALL Report, for Which

No Further Evaluation Is Required

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 Leakage Rate Testing Program

* Inservice Inspection-ASME Section Xl, Subsection IWE Program

* Inservice Inspection-ASME Section Xl, Subsection IWF Program

* - Inservice Inspection-ASME Section Xi, Subsection IWL Program

* Structures Monitoring Program

* Structures Monitoring-Crane Inspection Program

* Structures Monitoring-Divider Barrier Seal Inspection Program

* -Structures Monitoring-Ice Basket Inspection Program

* Structures Monitoring-Masonry Wall Program

* Water Chemistry Control Program

* System Testing Program

* -Fire Protection Program

Staff Evaluation

In Tables 3.5.2-1 through 3.5.2-5 of the LRA, the applicant provided a summary of AMRs for

the containment, containment internals; auxiliary building, turbine building, screenhouse, yard

structures; and structural commodities, and identified which AMRs are considered 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 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 describing the alignment of the

information in the tables with the information in the GALL Report. The staff audited those

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AMRs with notes A through E, where applicable, 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 identified by the applicant is

consistent with the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report and the validity of the AMR for the site-specific

conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the applicant took some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that it had reviewed and accepted the applicant's

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

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, but consistent with the

GALL Report for material, environment, and aging effect. In addition, the applicant took some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component applies to the component under review. The staff verified whether 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 credits a different AMP. 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 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 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 verify that the material presented in the LRA is applicable

and that the applicant identified the appropriate GALL Report AMRs.

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3.5.2.1.1 Loss of Material due to Corrosion in Accessible Areas Only

In LRA Table 3.5.1, Item 3.5.1-14, the applicant stated that a loss of material due to corrosion

in accessible areas only does not require further evaluation. The applicant does not rely upon

protective coatings to manage the effects of aging at CNP.

The staff noted that although the applicant did not credit protective coatings, damage to

protective coatings may accelerate corrosion. Therefore, the protective coatings have the

potential to exacerbate the aging effect. During the audit, the staff asked the applicant to

address damage to protective coatings. The applicant discussed the use of external coatings

and wrappings, the measures it takes during excavation of buried pipes, and inspections it

performs when buried pipe is exposed. The staff finds these explanations acceptable.

On the basis of its audit and review, the staff determined that the applicant's references to the

GALL Report are acceptable, that the line items are consistent with the GALL Report, and that

no further staff review is required with respect to AMRs not requiring further evaluation, as

identified in LRA Table 3.5.1.

In LRA Table 3.5.2-3, the applicant stated that the Structures Monitoring Program will be used

for the aging management of water control structures. In Section B.1.32 of Appendix B to the

LRA, the applicant stated that this program is consistent with the GALL Report. However, the

staff's review found that the applicant did not compare the Structures Monitoring Program with

GALL AMP XI.S7, "RG 1.127 Program," pursuant to the GALL Report. In order to ensure that

the Structures Monitoring Program can be used to cover the water control structures, the staff

requested the applicant to compare the Structures Monitoring Program with GALL AMP XL.S7

and demonstrate that the Structures Monitoring Program is suitable for managing the aging

effects of water control structures. The staff identified this as RAI 3.5-7.

In the submittal dated June 8, 2004, the applicant responded to this RAI as follows:

Regulatory Guide (RG) 1.127, Inspection of Water-Control Structures Associated

with Nuclear Power Plants, is identified as an acceptable basis for developing an

inservice inspection and surveillance program for water control structures in

NUREG 1801, Section XI.S7. For plants not committed to RG 1.127, such as

CNP, managing aging effects associated with structures and structural

components may be included in the Structures Monitoring Program. The major

water control structures at CNP are the screenhouse (intake structure) and the

roadway west of the screenhouse. CNP uses the Structures Monitoring Program

described in LRA Section B.1.32 to mange the effects of aging on water control

structures. The Structures Monitoring Program, with enhancements, is

consistent with NUREG-1801, Section XI.S6.

The attributes that are in NUREG 1801, Section XI.S7, aging management

program, but not in the CNP Structures Monitoring Program, are attributes

dealing with earthen embankments water control structures. NUREG 1801,

Section XI.S7, refers to RG 1.127 which proposes inspection parameters,

including 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,

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and frequency (not to exceed five years) for earthen embankment water control

structures. During the CNP aging management review, the aging effects

requiring management for earthen structures (roadway) were determined to be

loss of material, loss of form and change in material properties. As indicated in

LRA Section B.1.32, the Structures Monitoring Program will be enhanced to

include visual inspections to manage aging effects for the roadway west of the

screenhouse. The visual inspections will detect degradation of the roadway due

to the identified aging effects. The remaining water control structure

(screenhouse) is similar to other CNP structures that are addressed by the

Structures Monitoring Program. The Structures Monitoring Program will be

effective in managing the effects of aging for water control structures.

In addition, the applicant provided the following comparison of the CNP Structures Monitoring Program with GALL AMP XI.S7 to demonstrate the applicability of the Structures Monitoring Program for the aging management of water control structures:

Aging Management Program Elements

1. Scope of Program

a. NUREG 1801 Section XI.S7. Scope

RG 1.127 applies to water-control structures associated with emergency cooling water systems or flood protection of nuclear power plants. The

water control structures included in the RG 1.127 program are concrete

structures; embankment structures; spillway structures and outlet works; reservoirs; cooling water channels and canals, and intake and discharge structures; and safety and performance instrumentation.

b. Comparison

Water control structures are included in CNP Structures Monitoring Program. The Structures Monitoring Program scope includes the

screenhouse and, as indicated in LRA Section B.1.32, the program will

be enhanced to include the roadway west of the screenhouse.

2. Preventive Action

a. NUREG-1801. Section XI.S7. Preventive Action

No preventive actions are specified; RG 1.127 is a monitoring program.

b. Comparison

No preventive actions are included in the Structures Monitoring Program and none are required to address water control structures. The CNP

preventive actions are consistent with NUREG 1801, Section XI.S7.

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3. Parameters Monitored or Inspected

a:- NUREG 1801 Section XI.S7,-Parameters Monitored or Inspected

RG 1.127 identifies the parameters to be monitored and inspected for

water control structures. The parameters vary depending on the

particular structure. Parameters to be monitored and inspected for

concrete structures include cracking, movements (e.g., settlement,

heaving, deflection), conditions at junctions with abutments and -

embankments, erosion, cavitation, seepage, and leakage. Parameters to

be monitored and inspected for earthen embankment structures include

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. Further details of parameters to be monitored and

inspected for these and other water-control structures are specified in

Section C.2 of RG 1.127.

b. Comparison

For concrete water control structures at CNP, the specific parameters

monitored or inspected were selected to ensure that aging degradation

leading to loss of intended functions is detected and the extent of -

degradation is determined. The parameters monitored or inspected

(such as cracking, settlement, leakage, and water infiltration) were

selected considering industry codes, standards and guidelines, and also

consider industry and plant-specific operating experience. Settlement

and erosion of porous concrete subfoundations are not problems at CNP,

so a site de-watering system is not necessary. Consistent with NUREG1801, Section XI.S6, the Structures Monitoring Program adequately

addresses concrete and steel structure parameters to be monitored that

are applicable to water control structures.

The Structures Monitoring Program will be enhanced to include

parameters monitored for earthen structures (roadway west of the

screenhouse). In accordance with NUREG 1801, Section XI.S6,-

parameters to be monitored and inspected for earthen embankment

structures will consider industry codes, standards and guidelines, RG

1.127, and also consider industry and plant-specific operating

experience. -

4. Detection of Aging Effects

a. NUREG 1801. Section XL.S7, Detection of Aging Effects

Visual inspections are primarily used to detect degradation of water

control structures. In some cases, instruments have been installed to

measure the behavior of water-control structures. RG 1.127 indicates

that the available records and readings of installed instruments are to be

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- - .I

reviewed to detect any unusual performance or distress that may be

indicative of degradation. RG 1.127 describes periodic inspections, to be

performed at least once every five years. Similar intervals of five years

are specified in ACI 349.3R for inspection of structures continually

exposed to fluids or retaining fluids. Such intervals have been shown to

be adequate to detect degradation of water control structures before they

have a significant effect on plant safety. RG 1.127 also describes special

inspections immediately following the occurrence of significant natural

phenomena, such as large floods, earthquakes, hurricanes, tornadoes,

and intense local rainfalls.

b. Comparison

As indicated in LRA Section B.1.32, the Structures Monitoring Program

will be enhanced to include detection of aging effects for the roadway

west of the screenhouse. This enhancement will include inspecting the

roadway for degradation or damage following a significant natural

phenomenon, such as large floods, earthquakes, hurricanes, tornadoes,

and intense local rainfalls. When enhanced, the examination criteria for

the roadway will detect degradation of the roadway due to weather

related damage.

The screenhouse is designed as a seismic Class I structure providing

protection to safety related equipment from seismic events,

tornado-velocity wind effects, tornado-borne missiles and flood conditions

anticipated due to a seiche or surge phenomenon. Consistent with

NUREG 1801, Section XL.S6, the detection of aging effects for water

control structures concrete and steel elements is adequately addressed

in the Structures Monitoring Program. Inspection methods, inspection

schedule, and inspector qualifications are commensurate with industry

codes, standards, guidelines, and also consider industry and plant

specific operating experience. Special inspections are performed

following the occurrence of significant natural phenomena, such as

earthquakes, floods, seiche, severe weather, and fires.

5. Monitoring and Trending

a. NUREG 1801. Section XL.S7. Monitoring and Trending

Water control structures are monitored by periodic inspection as

described in RG 1.127. In addition to monitoring the aging effects

identified in Attribute (3) above, inspections also monitor the adequacy

and quality of maintenance and operating procedures. RG 1.127 does

not discuss trending.

b. Comparison

Consistent with NUREG-1 801, Section XL.S6, CNP structures are

monitored in accordance with 10 CFR 50.65. This approach is adequate

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for managing aging effects associated with water control structures

included in the Structures Monitoring Program.

6. Acceptance Criteria

a. NUREG 1801. Section XI.S7 RG 1.127,-Acceptance Criteria

Acceptance criteria to evaluate the need for corrective actions are not

specified in RG 1.127. However, the 'Evaluation Criteria' provided in

Chapter 5 of ACI 349.3R 96 provides acceptance criteria (including

quantitative criteria) for determining the adequacy of observed agingeffects and specifies criteria for further evaluation. Although not required,

plant-specific acceptance criteria based on Chapter 5 of ACI 349.3R 96

are acceptable. Acceptance criteria for earthen structures such as dams,

canals, and embankments are to be consistent with programs falling

within the regulatory jurisdiction of the Federal Energy Regulatory

Commission (FERC) or the U.S. Army Corps of Engineers.

b. Comparison

The Structures Monitoring Program acceptance criteria are consistent

with NUREG 1801, Section XL.S6, for concrete and steel components of

water control structures. Including the roadway west of the screenhouse

in the Structures Monitoring Program will result in developing acceptance

criteria for visual inspections. When enhanced, acceptance criteria will

be selected to ensure that the need for corrective actions will be identified

before loss of intended functions. Acceptance criteria will be

commensurate with industry codes, standards and guidelines, and will

also consider industry and plant-specific operating experience.

7, 8, 9. Corrective Actions, Confirmation Process, and Administrative Controls

CNP applies the requirements of 10 CFR Part 50, Appendix B, to the

Structures Monitoring Program through the use of the Corrective Action

Program. The Structures Monitoring Program Corrective Actions,.

Confirmation Process, and Administrative Controls attributes are applicable

to water control structures without enhancement.

10. Operating Experience

Operating experience discussed in LRA Section B.1.32 applies to water

control structures with the exception of the roadway west of the screenhouse.

Operating experience with the roadway was not discussed in LRA Section

B.1.32 since the Structures Monitoring Program does not yet include the

roadway; however, the operating experience review identified no significant

degradation of the roadway.

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The Structures Monitoring Program will effectively manage the aging effects

requiring management for water control structures at CNP with

enhancements identified in LRA Section B.1.32.

In summary, with enhancements, the Structures Monitoring Program will

effectively manage the aging effects requiring management for water control

structures at CNP.

The staff's review of this RAI response confirms that the applicant demonstrated that the

Structures Monitoring Program is suitable for managing the aging effects of water control

structures. On this basis, RAI 3.5-7 is resolved.

On the basis of its audit, the staff concludes that the applicant demonstrated that it will

adequately manage the effects so that the intended functions will be consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Conclusion

The staff verified the applicant's claim of consistency with 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 demonstrated that it will adequately manage the effects of aging for these

components so that their intended functions will be consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2 Aging Management Evaluations That Are Consistent with the GALL Report, for Which

Further Evaluation Is Recommended

In Section 3.5.2.2 of the LRA, the applicant provided further evaluation of aging management

for structures and component supports as recommended by the GALL Report. The applicant

provided information concerning how it will manage the following aging effects:

* aging of inaccessible concrete areas (PWR containments)

* cracking, distortion, and increases in component stress levels due to settlement, as well

as reduction of foundation strength due to erosion of porous concrete subfoundations, if

not covered by the Structures Monitoring Program (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 the 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 (PWR containments)

* aging of structures not covered by the Structures Monitoring Program (Class I

structures)

* aging management of inaccessible areas (Class I structures)

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* aging of supports not covered by the Structures Monitoring Program (component

supports)

* cumulative fatigue damage due to cyclic loading (component supports)

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 it further evaluated. In addition, the staff reviewed the applicant's further

evaluations against the criteria contained in Section 3.5.2.2 of the SRP-LR. The staff

documents its audit and review in the audit and review report.

The GALL Report indicates that the applicant should perform further evaluation for the aging

effects described in the following sections of this SER.

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.

Aging of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against the

criteria in SRP-LR Section 3.5.2.2.1.1. In LRA Section 3.5.2.2.1.1, the applicant 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 with the Inservice Inspection-ASME Section Xl, Subsection IWL Program

(CNP AMP B.1.17), which the staff evaluates in Section 3.0.3.2.8 of this SER. Subsection IWL

exempts from examination those portions of the concrete containment that are inaccessible

(e.g., foundation, below grade exterior walls, or concrete covered by a liner).

In the LRA, the applicant stated that it also used the Structures Monitoring-Structures

Monitoring Program (CNP AMP. B.1.32) where accessible areas are monitored for evidence of

aging effects that may be applicable to containment structures. The staff reviewed this

program and concludes that it is consistent with GALL AMP XL.S6. Section 3.0.3.2.12 of this

SER documents this program. -

The GALL Report, Volume 2, Chapter II, Table Al (as modified by ISG-3, "Concrete Aging

Management Program"), 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 components caused by these five aging mechanisms are

cracking, change in material properties, and loss of material.

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(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 clarified 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.

CNP is located in a region considered to be subject to moderate weathering conditions. In the

LRA, the applicant stated that its concrete structures are designed in accordance with 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

In the LRA, the applicant stated that CNP concrete also meets requirements of ACI 201.2R-77, "Guide to Durable Concrete." The specifications ACI 318-63 and ACI 201.2R-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 the loss of material from freeze-thaw has not been observed, either

through the Inservice Inspection-ASME Section Xl, Subsection IWL Program or the Structures

Monitoring Program.

On the basis that concrete satisfying 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 Inservice

Inspection-ASME Section Xl, Subsection IWL and Structures Monitoring Programs, the staff

finds that the containment Inservice Inspection Program will adequately manage 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 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 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, is well

cured, has low permeability, and that cracking is well controlled.

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In the LRA, the applicant stated that CNP concrete structures are not exposed to flowing water

and are designed in accordance with specification ACI 318-63 and meet the requirements of

guideline ACI 201.2R-77.

The staff finds that because ACI 318-63 provides assurance that the criteria of the GALL

Report and ISG-3 are met, leaching of calcium hydroxide is not significant at CNP, and

therefore the Inservice Inspection-ASME Section XI, Subsection IWL Program will be

sufficient to manage increases in porosity and permeability from 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 due to 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 criteria

defined in 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 ppm, or sulfates are

greater than 1500 ppm. The ISG-3 guidelines also state that a plant-specific program is

required to examine representative samples of below grade concrete when excavated for any

reason.

In the LRA, the applicant stated that the below grade environment is not aggressive (pH greater

than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm).

On the basis of the information provided 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 (spalling and scaling), and cracking due to aggressive chemical

attack are not significant for concrete in inaccessible areas. The staff finds that the applicant

has identified an appropriate plant-specific program for examining below grade concrete.

(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 updated the staff position that further evaluation is appropriate if

investigations, tests, or examinations have demonstrated that the aggregates are reactive.

In the LRA, the applicant stated that CNP concrete structures are designed in accordance with

ACI 318-63 and meet the requirements of ACI 201.2R-77. The ACI standards call for testing

aggregates at the time of construction.

On the basis of 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 CNP are not reactive.

The staff finds that this aging effect does not require management at CNP.

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(5) corrosion of embedded steel

Section 3.5.2.2.1.1 of the SRP-LR states that a 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 criteria defined in the GALL Report cannot be

satisfied.

For cracking, loss of bond, or loss of material (spalling and scaling) due to corrosion of

embedded steel, the GALL Report states that a plant-specific program is only required if the

below grade environment is aggressive. The ISG-3 guidelines also state that a plant-specific

program is required to examine representative samples of below grade concrete when

excavated for any reason.

In the LRA, the applicant credited the Inservice Inspection - ASME Section Xl, Subsection IWL and Structures Monitoring - Structures Monitoring Programs for corrosion of embedded steel in

accessible areas. In LRA Section 3.5.2.2.1.1, the applicant stated that, with respect to the

aging of inaccessible concrete areas, the below grade environment is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1500 ppm).

On the basis of interviews with the applicant's technical staff, the staff determined that the environment at the time of construction was not aggressive, and that on the basis of

subsequent testing it has remained within the limits identified in the GALL Report. The staff finds that this aging effect is not significant and is adequately managed in accordance with the criteria of the GALL Report.

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 the aging management of inaccessible concrete areas for the containment, as

recommended in the GALL Report and ISG-3.

The staff finds that the applicant has demonstrated that it will adequately manage the effects of

aging so that the intended functions will be consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Cracking. Distortion, and Increases in Component Stress Level due to Settlement: Reduction of Foundation Strength due to Erosion of Porous Concrete Subfoundations. if Not Covered by the Structures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2. In LRA Section 3.5.2.2.1.2, the applicant addressed (1) cracking, distortion, and increases in component stress level caused by settlement and (2) reduction of foundation strength resulting from erosion of porous concrete subfoundations in

the containment. The applicant used the Structures Monitoring-Structures Monitoring Program, where the applicant monitors accessible areas for evidence of aging effects that may be applicable to containment structures. Section 3.0.3.2.12 of this SER evaluates this program, which is consistent with GALL AMP XI.S6.

Section 3.5.2.2.1.2 of the SRP-LR states that cracking, distortion, and increases in component stress level resulting from settlement could occur in PWR concrete and steel containments. A

recent staff survey found that 12 nuclear reactor structures have porous concrete foundations

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with high alumina content, but CNP structures are not in this group. These foundations are

susceptible to reduction in strength and settlement potential resulting from erosion of cement

from porous concrete. 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 that

the applicant verify the continued functionality of the dewatering system during the'period of

extended operation. The GALL Report recommends no further evaluation if the scope of the

applicant's Structures Monitoring Program includes this activity.

The applicant stated in the LRA that it does not credit a dewatering system for controlling

settlement because the applicant monitored settlement at CNP and confirmed that significant

settlement is not occurring. Membrane waterproofing protects concrete within 5 feet of thehighest known ground water level and shields the containment building concrete against

exposure to ground water. Consequently, NRC IN 97-11, "Cement Erosion From Containment

Subfoundations at Nuclear Power Plants," dated March 21, 1997, does not identify CNP as a

plant susceptible to erosion of porous concrete subfoundations. Ground water was not -

aggressive during plant construction, and no changes in ground water chemistry conditions

have been observed. The applicant included these components within its plant-specific

Structures Monitoring Program, which will confirm adequate management of these aging

effects.

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,''

increases in component stress level from settlement, and reduction of foundation strength from

erosion, as recommended in the GALL Report..

The staff finds that the applicant has demonstrated that it will adequately manage the effects of

aging so that the intended functions will be consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

Reduction of Strength and Modulus of Concrete Structures due to Elevated Temperature. The

staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3. In

LRA Section 3.5.2.2.1.3, the applicant addressed the reduction of strength and modulus of

concrete structures caused by elevated temperature in containments.

Section 3.5.2.2.1.3 of the SRP-LR states that reduction of strength and modulus of elasticity

resulting from 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 of 66 0C (150 OF) and local area temperature of 93 OC (200 OF)).

In LRA Section 3.5.2.2;1.3, the applicant stated that during normal operation, all areas within

the containment building are below 66 0C (150 OF) ambient temperature except for the Unit 1

pressurizer enclosure, which is at 79 'C (160 OF). 'Several penetrations have been exposed to

temperatures greater than 93 OC (200 OF). However, these were temporary, and the effects

were negligible. Therefore, the applicant concluded that change in material properties from

elevated temperature is an AERM for the containment concrete only for the pressurizer

enclosure area for Unit 1, where ambient temperature exceeds 66 OC (150 OF).

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The applicant concluded that its containment concrete structures are not subject to change in

material properties resulting from elevated temperature. The applicant included these

components within the scope of the Structures Monitoring-Structures Monitoring Program, evaluated in Section 3.0.3.2.12 of this SER, and the Inservice Inspection-ASME Section Xl, Subsection IWL Program, evaluated in Section 3.0.3.2.8 of this SER, to monitor containment

concrete for indications of the change in material properties aging effects.

The staff reviewed the AMR results involving management of aging effects resulting from

elevated temperature and confirmed that the Inservice Inspection-ASME Section Xl, Subsection IWL and Structures Monitoring Programs address each of the affected SCs within

the pressurizer enclosure area. On the basis of this audit and review, the staff finds that the

applicant appropriately evaluated AMR results involving reduction of strength and modulus

resulting from elevated temperature, as recommended in the GALL Report.

On the basis that the concrete is only exposed to elevated temperatures within the pressurizer enclosure area, the staff finds that for all other locations the Structures Monitoring and Inservice

Inspection-ASME Section XI, Subsection IWL Programs will appropriately manage the aging effect during the period of extended operation. The staff finds that no further evaluation is

required.

The staff finds that the applicant has demonstrated that it will adequately manage the effects of

aging of the concrete resulting from elevated temperature 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).

Loss of Material due to Corrosion in Inaccessible Areas of Steel Containment Shell or Liner

Plate. The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section

3.5.2.2.1.4. In LRA Section 3.5.2.2.1.4, the applicant addressed the loss of material due to

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 the 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 specific criteria defined in the

GALL Report cannot be satisfied:

* Concrete meeting the requirements of ACI 318 and the guidance of ACI 201.2R was

used for the containment concrete in contact with the embedded containment shell or

liner.

* 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.

* 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

ASME Code, Section Xl, Subsection IWE requirements.

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* Borated water spills and water ponding on the containment concrete floor are not

common and when detected are cleaned up in a timely manner.

In the LRA, the applicant stated that the containment concrete in contact with the steel liner:

plate is designed in accordance with ACl 318-63 and meets the requirements of

ACI 201 .2R-77. Accessible concrete is monitored for cracks under the Structures Monitoring

Program. The accessible portions of the steel liner plate and moisture barrier where the liner

becomes embedded are inspected in accordance with the Inservice Inspection-ASME

Section Xl, Subsection IWE Program. Spills (e.g., borated water) are cleaned up in a timely

manner. The applicant also stated that the aging effect of loss of material due to corrosion has

not been significant for this liner plate.

The staff reviewed the Structures Monitoring Program and the Inservice Inspection-ASME

Section Xl, Subsection IWE Program and documents its evaluation in Sections 3.0.3.2.12 and

Section 3.0.3.2.7 of this SER, respectively. Based on its review and on the basis that all of the

criteria identified in the GALL Report are satisfied, the staff finds that an additional,

plant-specific AMP is not required to manage inaccessible areas of the steel containment liner

plate.

On the basis of its audit and review, the staff finds that the applicant has appropriately

evaluated AMR results involving loss of material due to corrosion that could affect inaccessible

areas of the steel liner plate and the containment liner plate. The staff finds that the applicant

has demonstrated that it will adequately manage the effects of aging so that the intended

functions will be consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated Temperature. Section

4.5 of this SER addresses Section 3.5.2.2.1.5 of the LRA.

Cumulative Fatigue Damage. Section 4.6 of this SER addresses LRA Section 3.5.2.2.1.6.

Cracking ue to Cyclic Loading and Stress Corrosion Cracking. The staff reviewed LRA Section

3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7. In LRA Section 3.5.2.2.1.7, the -

applicant addressed aging mechanisms that can lead to cracking of penetration sleeves and

penetration bellows, such as cyclic loads and SCC. Section 4.6 of this SER evaluates cracking

due to cyclic loading of the liner plate and penetrations, which is a TLAA.

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. Further evaluation of inspection methods is recommended

to detect cracking due to cyclic loading and SCC because visual examinations (VT-3) may be

unable to detect this aging effect.

GALL AMP XI.S1 covers inspection of these items under examination categories E-B, E-F, and

E-P (10 CFR Part 50, Appendix J pressure tests). 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 period of extended 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.

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In order to manage this aging effect, the applicant used the Inservice Inspection-ASME Section Xl, Subsection IWE Program, evaluated in Section 3.0.3.1 of this SER, and the

Containment Leakage Rate Testing Program, evaluated in Section 3.0.3.1 of this SER. Section

3.5.2.2.1.7 of the SRP-LR recommends further evaluation of this aging effect for stainless steel

penetration bellows and dissimilar metal welds. However, in LRA Tables 3.5.2-1 through

3.5.2-5, the applicant did not identify penetration bellows and dissimilar metal welds as subject

to an AMR.

On the basis that penetration bellows and dissimilar metal welds at CNP are not subject to an

AMR, the staff finds that cracking due to SCC is not an applicable aging effect for CNP.

Therefore, an augmented inspection to detect cracking is not necessary.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of cracking due to SCC for containment components, as

recommended in the GALL Report. Since the applicant's AMR results are otherwise consistent

with the GALL Report, the staff finds that the applicant has demonstrated that it will adequately

manage the effects of aging so that the intended functions will be consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2.2 Class 1 Structures

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2,

which addresses several areas discussed below.

Aging of Structures Not Covered by the Structures Monitoring Program. The staff reviewed

LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1. In LRA Section

3.5.2.2.2.1, the applicant 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. Chapter III of the GALL Report describes this and 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 increases in porosity and permeability due to 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 increases in component stress level

due to settlement for Group 1-3, 5, and 7-9 structures, (6) reduction of foundation strength due.-

to 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, as well as loss of material due to crevice

corrosion of the 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.

Section 3.5.2.2.1.2 of the SRP-LR presents technical details of the aging management issue for

structure/aging effect combination Items (5) and (6). Section 3.5.2.2.1.3 of the

SRP-LR presents technical details of the aging management issue for Item (8).

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In LRA Table 3.5.1, Item 20, the applicant credited its Structures Monitoring Program to

manage all types of aging effebts-and all component grouips except Group 6 of accessible

interior and exterior concrete, and steel components of Class 1 structures. The staff reviewed

this program and documents its evaluation in Section 3.0.3.2.12 of this SER. This section

provides additional discussion of specific structure/aging effect combinations.

(1) freeze-thaw

Section 3.5.2.2.1.2 of the SRP-LR does not address freeze-thaw as an aging mechanism for.

concrete containments because the GALL Report does not recommerd 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.

CNP is located in a region considered to be subject to moderate weathering conditions. In the

LRA, the applicant stated that CNP 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, the applicant stated in the LRA that its concrete also meets the

requirements of ACI 201.2R-77. The specifications ACI 318-63 and ACI 201.2R-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 from freeze-thaw has not been observed, either

through the Inservice Inspection-ASME Section Xl, Subsection IWL Program or the Structures

Monitoring Program.

On the basis that concrete satisfying 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 increase's 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,

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such leaching is not significant if the concrete is constructed to ensure that it is dense, well

cured, has low permeability, and that cracking is well controlled.

In the LRA, the applicant stated that its concrete structures are designed in accordance with

ACI 318-63 and meet the requirements of ACI 201.2R-77. The applicant also stated that its

concrete is not exposed to flowing water.

The staff reviewed relevant operating experience, interviewed members of the applicant's

technical staff, and reviewed ISG-3. The staff finds that, because ACI 318-63 provides

assurance that the criteria of the GALL Report and ISG-3 are met, and because the applicant's

concrete is not exposed to flowing water, leaching of calcium hydroxide is not significant at

CNP. Therefore, the staff concludes that the Structures Monitoring Program will be sufficient

for managing increases in porosity and permeability from 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 criteria defined in 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 ppm, or sulfates are

greater than 1500 ppm. The ISG-3 guidelines also state that a plant-specific program is

required to examine representative samples of below grade concrete when excavated for any

reason. In the LRA, the applicant stated that the below grade environment is not aggressive

(pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1500 ppm).

The staff reviewed the information provided in the LRA, the basis documents, and the

guidelines provided in the SRP-LR, the GALL Report, and ISG-3. On the basis of its review,

the staff finds that increases in porosity and permeability, loss of material (spalling and scaling),

and cracking due to aggressive chemical attack are not significant for concrete in inaccessible

areas. The staff finds that the applicant has identified an appropriate plant-specific program for

examining below grade concrete (specifically, an enhancement to the Structures Monitoring

Program).

(3) 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's position that further evaluation is appropriate if

investigations, tests, or examinations have demonstrated that the aggregates are reactive.

In the LRA, the applicant stated that its concrete structures are designed in accordance with

ACI 318-63 and meet the requirements of ACI 201.2R-77. The ACI standards call for testing

aggregates at the time of construction. On the basis of interviews with the applicant's technical

staff, the staff confirmed that the results of those tests show that the aggregates used for

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concrete Class 1 -structures at CNP are not reactive. The staff finds that no further evaluation is

required.

(4) corrosion of embedded steel

Section 3.5.2.2.2.1 of the SRP-LR states that the 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 criteria defined in the GALL Report cannot be satisfied.'

For cracking, loss of bond, and loss of material (spalling and scaling) due to corrosion of''

embedded steel, the GALL Report states that a plant-specific program is only required if the

below grade environment is aggressive. The ISG-3 guidelines also state that a plant-specific

program is required to examine representative samples of below grade concrete when

excavated for any reason.

In the LRA, the applicant stated that the below grade environment is not aggressive because

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 subsequent testing has shown the

environment has remained within these limits.-.

The staff finds that the applicant adequately manages this aging effect by the enhanced

Structures Monitoring Program, in accordance with the criteria of the GALL Report, which

Section 3.0.3.2.11 of this SER evaluates.

(5) settlement

Section 3.5.2.2.2.1 of the SRP-LR refers to Section 3.5.2.2.1.2 for discussion of settlement.

Section 3.5.2.2.1.2 of the SRP-LR states that cracking, distortion, and increases-in 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 verifying the continued functionality of the dewatering

system during the period of extended operation. The GALL Report recommends no further

evaluation if the scope of the applicant's Structures Monitoring Program includes this activity. -

In the LRA, the applicant stated that it did not credit a dewatering system for control of

settlement because it monitored settlement'and'confirmed that significant settlement was not

occurring. Membrane waterproofing protects concrete within 5 feet of the highest known

ground water level and shields the Class 1 concrete structures against exposure t6 ground

water. Consequently, IN 97-11 does not identify CNP as a plant susceptible to erosion of

porous concrete subfoundations.z Ground water was not aggressive during plant construction,

and no changes in ground water chemistry conditions have been observed. The applicant

included these components within its plant-specific Structures Monitoring Programr, which will

confirm adequate management of these aging effects. ' - -

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 appropriately evaluated AMR results involving cracking, distortion, and

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increases in component stress level from settlement and reduction of foundation strength from

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 resulting from erosion of porous concrete subfoundations could occur in all

types of 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 verifying the continued functionality of the dewatering system during the period of

extended operation. The GALL Report recommends no further evaluation if the scope of the

applicant's Structures Monitoring Program includes this activity.

The applicant stated that IN 97-11 does not identify CNP as a plant susceptible to erosion of

porous concrete subfoundations. Therefore, this issue is not applicable to CNP.

(7) corrosion of structural steel components

Section 3.5.2.2.2.1 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 the Structures Monitoring Program.

In LRA Section 3.5.2.2.1, the applicant stated that corrosion of structural steel components is

an aging effect managed by the Structures Monitoring Program.

The staff reviewed the AMR results involving management of aging effects resulting from the

corrosion of structural steel components and confirmed that the Structures Monitoring Program, evaluated in Section 3.0.3.2.12 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 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 a discussion of elevated

temperatures. Section 3.5.2.2.1.3 of the SRP-LR states that a reduction of strength and

modulus of elasticity resulting from 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 (ie.,

general area temperature 66 0C (150 0F) and local area temperature 93 0C (200 OF)).

In LRA Section 3.5.2.2.2.1, the applicant stated that during normal operation, all concrete areas

in Class 1 structures are below 66 0C (150 OF) ambient temperature except for the Unit 1

pressurizer enclosure, discussed in LRA Section 3.5.2.2.1.3. The staff's evaluation of the Unit

1 pressurizer enclosure elevated temperature appears in Section 3.5.2.2.1.3 of this SER.-

The staff reviewed the AMR results involving management of aging effects resulting from

elevated temperature and confirmed that the Structures Monitoring Program, evaluated in

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Section 3.0.3.2.12 of this SER, addresses each of the affected SCs. On the basis of this

review, the staff finds that the applicant appropriately evaluated AMR results involving the

reduction of strength and modulus resulting from elevated temperature, as recommended in the

GALL Report, and that the Structures Monitoring Program adequately manages this effect.

(9) aging effects for stainless steel liners for tanks

In LRA Section 3.5.2.2.2.1, the applicant stated that the structural AMRs do not include any

tanks with stainless steel liners. The applicant evaluated tanks that are subject to an AMR with

the respective mechanical system's AMR.

In LRA Section 3.5.2.2.2.1 and Tables 3.5.2-1 through 3.5.2-5, the applicant indicated that it will

not use the Structures Monitoring-Structures Monitoring Program (CNP AMP B.1.32) to

manage the aging effects resulting from the loss of material for those structural elements

potentially exposed to borated water leakage. These structural elements include block wall

grating and framing (carbon steel), missile shield (carbon steel), superstructure framing (carbon

steel), baseplates (carbon steel), baseplate of embedded unistrut (galvanized steel), blowout

panels (carbon steel), cable tray and conduit supports (carbon steel), cable trays and conduits

(galvanized steel and aluminum), component supports (carbon steel), electrical instrument

panels and enclosures (carbon steel), HVAC duct supports (carbon steel and galvanized steel),

instrument line supports (carbon steel and galvanized steel), instrument racks and frames

(carbon steel and galvanized steel), miscellaneous embedments (carbon steel), carbon steel

pipe sleeves (mechanicaVelectrical, not penetrating the containment liner plate), piping supports

(carbon steel), carbon steel stair systems (stairs, ladders, and grating including supports), tube

tracks (carbon steel), carbon steel anchor bolts (includes switchyard structures and tank

anchors), Class 1 anchor bolts (carbon steel), certain threaded fasteners (carbon steel), and

reactor cavity missile block tiedowns (carbon steel).

For the aging effects caused by boric acid corrosion, the applicant proposed to use the Boric

Acid Corrosion Prevention Program (CNP AMP B.1.4). As stated in the LRA, this program is

comparable with GALL AMP XI.M1 0. The LRA also states that, with program enhancement to

include electrical components in addition to ferritic steel, this AMP will be consistent with the

program described in GALL AMP XI.M1 0, and will be used to cover steel structural elements

related to or adjacent to the boronic injection system, including those located inside the auxiliary

building.

The staff's review of LRA Table 3.5.2-5 found that this AMP will be used to manage aging

effects related to the loss of materials in some structural elements, such as anchor bolts of

switchyard structures and tank anchors. Therefore, in RAI 3.5-6, the staff requested that the

applicant (a) clearly state that the scope of this AMP will cover these structural elements and (b)

clarify whether this AMP will cover any other structures and structural components not located

in the containment or the auxiliary building.

In the submittal dated June 8, 2004, the applicant provided its response to these two questions

as follows:

(a) The Boric Acid Corrosion Prevention Program is implemented by a plant

procedure. The procedure is applicable where the potential exists to degrade

ferritic steel components within the reactor coolant pressure boundary and

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other plant systems due to contact with borated water. The scope of the

Boric Acid Corrosion Prevention Program includes structures and structural

components potentially exposed to borated water leakage, whether they are

included in the containment, auxiliary building, or other locations on the plant

site (including yard structures). Switchyard structures are not exposed to

borated water leakage, but some tank anchors are, as discussed in response

to sub-part (b), below.

(b) The Boric Acid Corrosion Prevention Program listed for anchor bolts in LRA

Table 3.5.2 5 applies only to anchor bolts with the potential for exposure to

borated water leakage. Structural components located outside the

containment and auxiliary buildings that are covered by the Boric Acid

Prevention Corrosion Program are the refueling water storage tank

anchorage in the yard.

In its response, the applicant clarified that the Boric Acid Corrosion Prevention Program will

cover structures and structural components potentially exposed to borated water leakage,

whether they are included in the containment, the auxiliary building, or other locations on the

plant site (such as yard structures), including the anchors of switchyard structures and tanks.

On this basis, RAI 3.5-6 is resolved.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving aging management of accessible interior and exterior concrete and steel

components of Class 1 structures (except Group 6, water-control structures, discussed in

Section 3.0.3.2.11 of this SER), and the Structures Monitoring Program covers them all. This is

consistent with the recommendations of the GALL Report. The staff 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 for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 against

the criteria in SRP-LR Section 3.5.2.2.2.2. In LRA Section 3.5.2.2.2.2, 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 resulting from aggressive chemical attack, as well as cracking, spalling, loss of

bond, and loss of material due to corrosion of embedded steel could occur in below grade

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

below grade environment exists. The ISG-3 guidelines identify additional requirements.

The GALL Report, as updated by ISG-3, states that aggressive chemical attack and corrosion

of embedded steel are not significant unless pH is less than 5.5, chlorides are greater than

500 ppm, or sulfates are greater than 1500 ppm. The ISG-3 guidelines also state that a

plant-specific program is required to examine representative samples of below grade concrete

when excavated for any reason.

In the LRA Section 3.5.2.2.2.2, the applicant stated that the below grade environment is not

aggressive (pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than

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1500 ppm). Inspections of accessible concrete have not revealed degradation from aggressive

chemical attack or corrosion of embedded steel.

On the basis that the below grade environment is' not aggressive, and that excavated concrete

has been and will continue to be monitored, the staff finds that the applicant adequately

manages increases in porosity and permeability, loss of material (spalling and scaling), and

cracking due to aggressive chemical attack, as well as cracking, spalling, loss of bond, and loss

of material due to corrosion of embedded steel for-concrete in inaccessible areas.

In LRA Section 3.5.2.2.2.2, the applicant stated that inspection of accessible concrete has not

revealed degradation related to corrosion the of embedded steel. The applicant also stated that

as the CNP below grade environment is not aggressive, corrosion of embedded steel is not an

applicable aging mechanism for CNP concrete. The staff agrees with this statement only for

the case of uncracked reinforced concrete elements. -However, the staff is concerned that the

embedded structural foundations may crack from settlement, and corrosion of reinforcing steel

may occur, even if the below grade environment is not aggressive. The staff requested the

applicant to provide additional information to justify the validity of the LRA statement. The staff

identified this as RAI 3.5-5.

In the response dated June 8, 2004, the applicant stated the following:

As discussed in LRA Section 3.5.2.2.1.2, cracking due to settlement is not

applicable to CNP concrete structures. Settlement was monitored at CNP until

discontinued after confirmation that significant settlement was not occurring. In

addition, NUREG 1800, Section 3.5.2.2.2.2, recommends further evaluation to

manage aging effects only if specific criteria defined in NUREG 1801 cannot be

-met. Those criteria are the criteria for an'aggressive environment as stated in

NUREG 1801, Volume 2, Item III.A1.1 e. Since the CNP below-grade

environment is not aggressive, corrosion of embedded steel is not an applicable

aging effect/mechanism.

In addition to the response above, the applicant provided its monitoring results of ground water

chemistry in its response to RAI 3.5-8, and indicated that the pH is higher than 5.5, the chloride

contents are much lower than 500 ppm, and sulfate contents are much lower than 1500'ppm.

According to GALL-Report, Volume 2, Item IlI.A3.1-e, the below grade environment is not

aggressive, and the aging effect resulting from rebar corrosion will be insignificant, so no further

evaluation is necessary. On this basis,- RAI 3.5-5 is resolved.

Section 3.5.2.2.2.1.(2), "Leaching of Calcium Hydroxide and Aggressive Chemical Attack," of

the LRA states that the CNP concrete is not exposed to flowing water, and the below grade

environment is not aggressive (pH is greater than 5.5, chlorides are less than 500 ppm, and

sulfates are less than 1500 ppm). Therefore, the LRA'concludes that increases in porosity and

permeability and loss of strength of due to leaching of calcium hydroxide are not applicable

aging effects for CNP concrete structures. However, in the'Structures Monitoring Program, the

applicant did not commit to periodically monitor the ground water chemistry as specified in the - -

GALL Report. Therefore,- the staff requested the applicant to (1) either augment its Structures

Monitoring Program to include the monitoring of ground water chemistry in order to ensure that

the ground water will be continuously nonaggressive or (2) provide a technical basis to justify

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that there is no need to continuously monitor the ground water chemistry. The staff identified

this as RAI 3.5-8.

In its response, the applicant stated the following:

Sample data tabulated below indicates the limiting chemistry parameters have

shown no significant increase and are still far below established limits. Because

existing data show no significant change over a period of approximately 25

years, ground water chemistry is not anticipated to significantly change in the

future. Therefore, periodic monitoring of ground water chemistry is not required

to assure the non aggressiveness of the below grade environment.

ample S ample date Sample Well 1A | Sample Well 12

03/04/1976 6.4 7.8

pH 01/15/2002 7.1 7.4

03/04/1976 20.3 9.7

Chloride (ppm) 01/15/2002 10 12

03/04/1976 18.1 310.3

Sulfate (ppm) 01/15/2002 13467 _15_ ___ 01___ __ __ 134 67

On the basis of the information provided above, the staff concurs with the applicant's conclusion

that the changes in water chemistry for the past 25 years are insignificant and the total water

contents are much lower than the GALL Report criteria. In addition, Appendix B to the

applicant's environmental report for the operating license renewal stage (i.e., the license

renewal environmental report) excerpts the discharge permit (MDEQ permit No. M00988) and

states that the discharge permit requires groundwater sampling from four onsite wells (plus a

background monitoring well). The quarterly monitoring includes sampling and analyzing the

ground water for pH, chloride, sulfates, and a number of other parameters. According to the

applicant, this requirement has been implemented since 1984. The results of this sampling,

including compliance with specified limitations, are reported to the Department of Environmental

Quality (DEQ) on a quarterly basis, and can be used to justify the quality of groundwater. On

the basis discussed above, the staff considers RAI 3.5-8 resolved.

3.5.2.2.3 Component Supports

The staff reviewed LRA Section 3.5.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.3,

which addresses several areas discussed below.

Aging of Supports Not Covered by the Structures Monitoring Program. The staff reviewed LRA

Section 3.5.2.2.3.1 against the criteria in SRP-LR Section 3.5.2.2.3.1. In LRA Section

3.5.2.2.3.1, the applicant addressed aging of component supports that are not managed by the

Structures Monitoring Program.

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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 the

Structures Monitoring Program. This includes-(1) reduction in concrete anchor capacity:

resulting from the 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 resulting from the degradation of vibration isolation elements for Group B4

supports. Further evaluation is necessary only for structure/aging effect combinations not

covered by the Structures Monitoring Program.

(1) reduction in concrete anchor capacity resulting from surrounding concrete for Group

B1-B5 supports

In LRA Section 3.5.2.2.3.1, the applicant stated that the Structures Monitoring Program

includes its component supports for Groups B2-B5, and the Inservice Inspection-ASME

Section Xl, Subsection IWF Program manages component supports for Group B1. The staff

reviewed these programs and documents its evaluation in Sections 3.0.3.2.12 and 3.0.3.1 of

this SER, respectively.

On the basis of its review of the AMR results involving the aging effects of reduction in

concrete anchor capacity from surrounding concrete, as well as its review of the AMPs that

manage the aging effects, the staff finds that the applicant adequately manages these aging

effects for component supports.

(2) loss of material due to environmental corrosion for Group B2-B5 supports

In LRA Section 3.5.2.2.3.1, the applicant stated that the loss of material due to corrosion of

steel support components is an AERM at CNP. The applicant manages this aging effect with

the Structures Monitoring Program. The staff finds that the applicant adequately manages this

aging effect for component supports.

(3) reduction/loss of isolation function resulting from degradation of vibration isolation

elements for Group B4 supports

In LRA Section 3.5.2.2.3.1, the applicant stated that no vibration isolation elements for Group

B4 supports are subject to an AMR. The staff finds that the applicant has appropriately

evaluated AMR results involving the aging management of component supports, as

recommended in the GALL Report. The staff finds that the applicant demonstrated that it will

adequately manage the effects of aging so that the intended functions will be consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Cumulative Fatigue Damage due to Cyclic Loading. Section 4.6 of this SER evaluates

cumulative fatigue damage as a TLAA.

3.5.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components

The NRC Office of Nuclear Reactor Regulation, Division of Inspection Program Management

staff reviewed LRA Section 3.5.2.2.4. Section 3.0.4 of this SER addresses this issue.

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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 adequately addressed'

the issues it further evaluated. In addition, the staff reviewed the applicant's further evaluations

against the criteria contained in 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 it will adequately manage the effects of aging so that the intended functions will be

consistent with the CLB during 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 or Are Not Addressed in

the GALL Report

Summary of Technical Information in the Application

In Tables 3.5.2-1 through 3.5.2-5 of the LRA, the staff reviewed additional details of the results

of the AMRs for materials, environments, AERMs, and AMP combinations that are not

consistent with the GALL Report.

In Tables 3.5.2-1 through 3.5.2-5, the applicant indicated with notes F through J, where

applicable, that the GALL Report does not evaluate either the identified components or the

material and environment combinations. The applicant provided information concerning how it

will manage the AERMs.

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.

Note J indicates that neither the identified component nor the material and environment

combination is evaluated in the GALL Report.

Staff Evaluation

For component type, material, and environment combinations that are not evaluated in the

GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant demonstrated that it will adequately manage the effects of aging so that the intended functions

will be consistent with the CLB during the period of extended operation. The following sections

discuss the staff evaluation.

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3.5.2.3.1 Containment

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 for containment components. The applicant identified the following AMPs that will

manage the aging effects for the containment components:

* Boric Acid Corrosion Prevention Program

* Containment Leakage Rate Testing Program

* Inservice Inspection-ASME Section Xl, Subsection IWE Program

* Inservice Inspection-ASME Section Xl, Subsection IWF Program

* Inservice Inspection-ASME Section XI, Subsection IWL Program

* Structures Monitoring Program

* Structures Monitoring-Crane Inspection Program

* Structures Monitoring-Divider Barrier Seal Inspection Program

* Structures Monitoring-Ice Basket Inspection Program

* Water Chemistry Control Program

In Table 3.5.2-1 of the LRA, the applicant summarized the AMRs for the containment

components and identified AMRs it considered to be not consistent with or not addressed in the

GALL Report.

Staff Evaluation

The following paragraphs discuss RAls related to the containment pressure boundary

components as summarized in Tables 3.5.1 and 3.5.2-1, the applicant's responses, and the

staff's positions.

Aging Effects

RAI 3.5-1

In discussing Item 3.5.1-3 of Table 3.5.1 of the LRA, the applicant indicated that the aging

effects related to the loss of material due to corrosion-of bellows and dissimilar metal welds are

managed consistent with the GALL Report. The GALL Report recommends examining - - -

penetration bellows and the associated dissimilar welds based on operating experience with the

SCC of bellows as documented in NRC IN 92-20, "Inadequate Local Leak Rate Testing," dated

March 3, 1992.. In RAI 3.5-1, the staff requested the following in relation to the examination

and/or testing of containment penetration bellows:

How many penetration bellows are in the Cook containments? Please summarize'the'

operating experience related to the examination of these bellows. If provisions are

made to assess their leaktightness (as they are not accessible for visual examination),

please provide a summary of these provisions (including frequency of tests), and

indicate if such leaktightness assessment of the bellows is part of the LRA AMP [aging

management program] B.1.15 or B.1.8.

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L

In its response, the applicant stated the following:

As stated in Updated Final Safety Analysis Report (UFSAR) Section 1.4.7,

Criterion 56, and Section 5.2.4.2, Fuel Transfer Penetration, penetration

expansion bellows are not used to maintain containment integrity and do not

serve as part of the containment pressure boundary. Therefore, CNP expansion

bellows do not serve an intended function, and are not subject to aging

management review. No provisions are made to assess their leaktightness.

For the purpose of clarification, the staff requested the applicant to confirm that the CNP

containments do not have any containment pressure boundary bellows.

In response, the applicant stated the following:

Containment penetration bellows do not provide a pressure-boundary function

and are not part of the CNP containment isolation barrier. The Updated Final

Safety Analysis Report excerpts provided in l&M's original response to RAI 3.5-1

in the l&M letter dated June 8, 2004, (Reference 1) provide the current licensing

basis that reflects this. This basis has also been previously been reported to,

and reviewed by, the NRC Staff in the l&M license amendment request dated

April 11, 2002 (Reference 2) and the NRC safety evaluation that approved the

license amendment, dated February 25, 2003 (Reference 3).

For clarification, the component type "Fuel transfer tube penetration" listed in

LRA Table 3.5.2-1 includes only the mechanical components (tube and closure

flange) that are depicted on license renewal drawings LRA-1 -5140 and LRA-2-

5140 at locations L8 and L4, respectively. The bellows expansion joints that

were provided on the outer pipe to compensate for any differential movement

between the inner and outer pipes and also between the containment and

auxiliary building structures do not serve as part of the containment pressure

boundary. Because penetration bellows do not provide a containment

pressure-boundary function, they are not included in the scope of license

renewal and are not subject to aging management.

During a telephone conference call dated September 16, 2004, the applicant explained the

purpose of bellows associated with the fuel transfer tube penetration as providing flexibility of

movement between the fuel transfer tube and its penetration sleeves. As indicated in Figure

5.2-4 of the CNP UFSAR, the penetration bellows are welded to the fuel transfer tube prior to

penetrating through the containment liner, and the bellows do not perform a pressure boundary

function. The staff accepted the explanation and concluded that the bellows are neither

required to be in scope of license renewal nor subject to aging management. Therefore, RAI

3.5-1 is closed.

RAI 3.5-2

In Item 3.5.1-6 of the LRA, the applicant provided the containment Inservice Inspection

Program and the Containment Leakage Rate Testing Program as the AMPs for seals and

gaskets related to containment penetrations. For equipment hatches and airlocks at CNP, the

staff agrees with the applicant's assertion that the Containment Leakage Rate Testing Program

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will monitor aging degradation of their seals and gaskets, as they are leak-rate tested after

each closing. For other penetrations with seals and gaskets, the staff requested the applicant

to provide information regarding the adequacy of Type B LRT frequency to monitor aging

degradation of seals and gaskets at CNP.

In response, the applicant stated the following:

The line item for "Air lock seals" in LRA Table 3.5.2-1 (Page 3.5-39) is the only

line item for seals or gaskets in which l&M credits the Containment Leakage

Rate Testing Program. The air lock seals line item is also the only line item that

refers to Item 3.5.1-6, "Seals, gaskets, and moisture barriers," of LRA Table

3.5.1.

In its subsequent request, the staff pointed out the following:

Item II A3.3-a (Page # II A3-5) of NUREG-1801 addresses the aging management of

seals, gaskets, etc. which are part of the containment pressure boundary, i.e. seals and

gaskets of equipment hatches, and mechanical & electrical penetrations. If I & M plans

to monitor only Air lock seals by means of containment leakage rate testing, then the

applicant is requested to provide additional information regarding the aging

management of seals and gaskets of equipment hatches, and mechanical and electrical

penetration associated with the containment pressure boundary. If I & M intends to use

containment leak rate testing program (Type B test of Appendix J) for aging

management of these seals and gaskets, the applicant is requested to provide

additional information as requested in RAI 3.5-2.

In response, the applicant provided the following information:

As indicated in LRA Table 3.5.1, the Containment Leakage Rate Testing

Program is credited for aging management of seals and gaskets that are part of

the containment pressure boundary (i.e., seals and gaskets associated with

equipment hatches and with mechanical and electrical penetrations). In LRA

Table 3.5.1, equipment and personnel hatches are included in Item Number

3.5.1-4, and seals and gaskets are included in Item Number 3.5.1-6.

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 Leakage Rate Testing 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 Leakage Rate Testing Program.

The effects of aging on seals and gaskets associated with mechanical and

electrical penetrations are also managed by the Containment Leakage Rate

Testing Program. LRA Table 3.5.1, Item Number 3.5.1-6, also includes seals

and gaskets associated with mechanical and electrical penetrations.

CNP is committed to Option B of 10 CFR 50, Appendix J, for performing

containment leakage rate testing. In accordance with Option B, Type B test

intervals are limited to 120 months; however, testing is normally performed more

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frequently than every 120 months. Type B testing of CNP 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 clarification emphasizes that the applicant will use the Containment Leakage Rate Testing Program to manage the aging of the seals and gaskets associated with airlock, equipment hatches, and electrical and mechanical penetrations. The clarification also provides the

process used in determining the test interval. Based on this information, the staff closed RAI

3.5-2.

RAI 3.5-3

On the subject of degradation of moisture barriers and subsequent liner corrosion, the staff

requested the applicant to provide information regarding the operating experience related to the

degradation of moisture barriers and the containment liner plate at CNP. The staff also

requested the applicant to discuss acceptable liner plate corrosion before it was reinstated to

the nominal thickness.

In response, the applicant stated the following:

In the past, instances of containment liner degradation in the vicinity of the

moisture barrier have been identified on both CNP units. However, in only one

case was the minimum containment liner thickness found to be less than the

acceptance criterion (0.250 inches). In March 1998, an inspection of the Unit 1

containment liner plate identified aging degradation of moisture barrier seal due

to poor maintenance and the consequent pitting. The inspection reported the

thickness of the steel containment liner to be less than 0.250 inches. The cause

of the pitting was determined to have been inadequate installation practices at

the time of original construction and a lack of proper maintenance of the seal

located between the concrete floor slab and the steel liner. As documented in

Unit 1 LER 98-011-02, an analysis of this event determined that the identified

steel containment liner pitting would be of no safety significance, as the leaktight

integrity of the containment would not be impaired and the as-found liner will

continue to fulfill its function as an effective leaktight membrane. The existing

seal was removed and the surface on the containment liner plate prepared and

coated with new seals applied. American Society of Mechanical Engineers

(ASME) Boiler and Pressure Vessel Code, Section Xl, Subsection IWE, provides the requirements for inservice inspection of containment structures. The

requirements include examination, evaluation, repair, and replacement of

concrete containment liner plate in accordance with 10 CFR 50.55a. The

acceptance criteria for CNP liner plate are in accordance with ASME Boiler and

Pressure Vessel Code, Section Xl, Subsection IWE.

The staff review of LER 98-011-02 indicates that the applicant developed an approach for

dealing with the issue of liner corrosion at CNP Units 1 and 2. The staff finds the approach acceptable as it is based on ASME Code, Section Xl, Subsection IWE, as incorporated by reference in 10 CFR 50.55a (CNP AMP B.1.15 of the LRA).

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In related RAI 3.5-9, the staff requested that the applicant provide additional information related

to the degradation of the containment liner plate behind the ice baskets and the method for

monitoring the degradation.

By the letter dated November 18, 2004, the applicant provided the following information:

Permanently installed wall panels separating the liner from the ice baskets

prevent ingress of water/moisture between the ice baskets and the liner plate.

The liner plate areas behind each unit's ice condenser are inspected as part of

inservice inspection through three existing 14-inch diameter circular ports.

These inspections are identified in the CNP Containment Inservice Inspection

Program Plan, which is part of the aging management program described in LRA

Section B.1.15. The inspection results have not indicated the need for

augmented inspection.

Other than the inspection port openings, access to the concrete liner behind the

permanent ice condenser wall panels would require destructive activities, such

as dismantling or modification of the wall panels, removal of divider barrier seal

material, or removal/displacement of the ice condenser top deck curtain.

Sections of the divider barrier seal material are removed each outage for testing

(i.e., test coupons). -With the divider barrier seal test coupons removed, a limited

view of the liner plate exists through a small gap in the divider barrier steel. I&M

implements a recurring task work order to perform a "best effort" visual

examination of the liner through this small gap to identify any liner degradation.

In the response, the applicant also indicated that there is a narrow gap at the top of the ice

condenser in the area of the top deck doors behind the top deck vent curtain.. A limited

inspection of the liner behind the ice baskets can be performed; however, it would require a

number of potentially destructive activities.

Recognizing the difficulties in conducting these inspections, the staff relies on the applicant's

best efforts in detecting degradation of the containment liner plate behind the ice-baskets and

its approach to identifying degradation during the period of extended operation. However, the

applicant may opt to change its approach if the industry-wide experience related to the

degradation of the containment liner (or shell) behind the ice-baskets indicates significant

degradation in this area in the future. Therefore, the staff's concern described in RAI 3.5-3 has

been resolved.

RAI 3.5-4

In addressing Item 3.5.1-27 in LRA Table 3.5.2-1, for the reinforced concrete structures

subjected to elevated temperatures and high humidity (e.g., primary shield walls, pressurizer

and steam generator enclosures, and reactor vessel supports), the staff's position is that the

"Environment" column should state "elevated temperature." For these structures, the staff

requested the that applicant 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.

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(b) If the primary shield wall concrete (or any other structure within CNP containment) is

kept below the threshold temperature (i.e., 66 0C (150 OF) by means of air cooling,

provide the operating experience related to the performance of the cooling system.

(c) Provide the results of the latest inspection of these structures, in terms of cracking,

spalling, and condition of reactor vessel support structures.

In its response, the applicant pointed out that the appropriate pressurizer enclosure component

type and environment entries listed in LRA Table 3.5.2-1 on page 3.5-38 are "Pressurizer

enclosure (Unit 1)" and "Protected from weather with elevated temperature," respectively.

Table 3.0.2 of the LRA defines the environment on page 3.0-10.

In response to the staff request in item (a), the applicant stated the following:

The primary containment upper and lower compartment average temperature is

monitored at various containment building elevations in accordance with

applicable technical specifications. However, the temperatures within the

primary shield wall concrete, around the reactor vessel, and in the reactor cavity

are not directly monitored.

In response to the staff request in item (b), the applicant stated the following:

The containment ventilation system is designed to maintain a maximum

temperature of 100 OF in the containment upper compartment during plant

operation, and a maximum temperature of 120 0F in the lower compartment (135

IF inside the primary concrete shield) during plant operation. A search of the

corrective action program database for condition reports (CRs) generated over

the past five years discovered two CRs that relate to the performance of

containment cooling ventilation systems. Both these CRs were resolved as

follows:

* A Unit 1 pressurizer enclosure ventilation exhaust fan had significantly lower

output than its alternate train fan. A job order adjusted the back draft

damper to correct fan performance.

* A pressurizer enclosure ventilation exhaust fan discharge backdraft damper

was found to be stuck open with broken linkage. A job order replaced the

back draft damper.

The applicant further noted that none of the CRs indicated pressurizer compartment

temperatures to be in excess of 66 OC (150 0F).

In response to item (c), the applicant provided a detailed discussion of examinations it

performed in November 1999, April 2003, and November 2003, as follows:

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Concrete examinations November 1999

The concrete surfaces below the nozzles of the reactor vessel in CNP Unit 2

were examined on November 12, 1999. The methods of examination were --

visual observation and sounding of the concrete surfaces with a hammer.

The scope of the examination was the horizontal concrete surfaces located at

elevation 609' 2 below the Number 2 inlet, and the Number 1 outlet nozzles.

Steel reactor supports are located at each nozzle. The junction of the two

flanges between the upper and lower portion of the support is approximately 6"

above the concrete surfaces observed.

In each location, there was a thin crack parallel to the steel support,

approximately 8" to 10" away from the outside of the support. A similar width

crack, normal to the support centerline, extended from the center stiffener plate

to the parallel crack. The cracks observed were between 1/32" and 1/8" in width

at the surface and the width tapered to hairline width within 1/16" of the surface.

-Solid ringing sounds were produced in response to hammer strikes on all of the

accessible surface area. There was no evidence of moisture movement through

the cracks or any structural distress or material deterioration of the concrete.

The concrete in question was placed in four 450 sectors, at each support

location, between elevations 607' 7" and 609' 2", after the supports were

installed. It appeared that the concrete did not support mechanical loads and

that its primary function is to fill the space left in the pedestal for installation of

the reactor supports. The observed cracks were probably caused by drying

shrinkage and were not considered unusual. It did not appear that there has

been significant moisture movement through the cracks, and it is doubtful that

serious corrosion has resulted in the embedded portion of the support. -

Therefore, no remedial action was considered necessary for the concrete

examined.

Concrete examinations April 2003 and November 2003

A summary of the inspection results of the Unit 1 and Unit 2 biological shield

walls in the Containment Buildings is provided below. These inspections were

performed during the U1C19 (November 2003) and U2C14 (April 2003) refueling

outages.

Starting at elevation 598' (which is about 12 feet below the vessel supports) and

going upward, both wall exterior faces are in very good condition. The walls

exhibited a few, limited, scattered, hairline cracks. The longest hairline cracks

were no more than ten feet long. Almost all of the observed cracks were

between elevation 598' and about 608' (between the floor and a horizontal

construction joint). There was very little indication of efflorescence (calcium

deposits) in these cracks. There were no indications of any spalling. The

condition of the walls (very limited cracking) can be attributed to their extremely

robust design. The walls at this location are approximately seven feet thick, with

several layers of reinforcing steel bars.

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The staff finds the applicant's approach in monitoring these structures acceptable, as (1) the

applicant has adequate controls that would indicate the malfunctioning of fans and coolers that

control the temperature around the reactors and pressurizer enclosures, and (2) the applicant

inspects the condition of the concrete structures around the reactor and in the pressurizer

enclosure that will maintain the intended functions of these structures during the period of

extended operation. Therefore, the staff's concern described in RAI 3.5-4 has been resolved.

Aging Management Programs

The staff reviewed Table 3.5.2-1 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the containment structures component groups.

In the LRA, the applicant stated that it manages the loss of material for stainless steel fuel

transfer tube penetration component types exposed to borated water using the Inservice

Inspection-ASME Section Xl, Subsection IWE and Containment Leakage Rate Testing

Programs. The staff reviewed these programs and documents its evaluations in Sections

3.0.3.2.7 and 3.0.3.1 of this SER, respectively. Because this is consistent with the GALL

Report recommendation for components with the same material, environment, and aging effect,

the staff finds this to be acceptable.

In the LRA, the applicant stated that it manages the loss of material for galvanized steel ice

baskets exposed to borated ice using the Structures Monitoring-Ice Basket Inspection

Program. The staff reviewed this program and documents its evaluation in Section 3.0.3.3.12

of this SER. On the basis of the operating experience and root causes identified for corrective

work, the staff concluded that this is acceptable.

In the LRA, the applicant stated that it manages the loss of material for the galvanized steel ice

condenser lattice frame, carbon steel ice condenser lower support structure, and carbon steel

ice condenser turning vanes exposed to borated ice using the Structures MonitoringStructures Monitoring Program. The staff documents its evaluation of this program in Section

3.0.3.2.12 of this SER. The applicant also stated that it manages the loss of material of the

stainless steel ice condenser wall duct panels component type exposed to borated ice using the

same program. On the basis that the Structures Monitoring Program is consistent with GALL

AMP XL.S6 and adequately manages the loss of material for these components, the staff finds

this acceptable.

In the LRA, the applicant stated that it manages loss of material for carbon steel reactor vessel

supports (water cooled) exposed to treated water using the Water Chemistry Control-Closed

Cooling Water Chemistry Control and the Inservice Inspection-ASME Section Xl, Subsection

IWF Programs. The staff reviewed these programs and documents its evaluations in Sections

3.0.3.2.16 and 3.0.3.1 of this SER, respectively. Because these programs are consistent with

the GALL Report recommendation for other components with the same material, environment,

and aging effect, the staff finds this to be acceptable.

The applicant stated in the LRA that it identified no aging effects for stainless steel components

exposed to air (protected from weather), including removable gate (bulkhead), seal table, and

sump screens component types. The applicant identified no aging effects for galvanized steel

sump screens and associated framing exposed to air (protected from weather). The GALL

Report does not identify air as an environment for these components and materials.

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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, indoor, or in an

air-conditioned enclosure or room). Significant corrosion of carbon and LAS requires an

electrolytic environment and a simultaneous presence of oxygen and moisture.' Without the'

presence of the aggressive environment, LAS components will experience insignificant

amounts-of corrosion, and no aging effects are applicable to this component/commodity group.

Therefore, the staff concludes that metal in a dry air environment has no AERMs.

In the LRA, the applicant stated that it manages loss of material for cadmium-plated steel

threaded fasteners (ice basket) exposed to borated ice using the Ice Basket Inspection

Program. On the basis of the operating experience and root causes identified for corrective

work, the staff concludes that this is acceptable.

In the LRA, the applicant stated that it manages reinforced concrete protected from the weather

using the Structures Monitoring Program and the Inservice Inspection-ASME Section Xi,

Subsection IWL Program for the containment base slab foundation component type. The

applicant also stated that it manages reinforced concrete exposed to weather using the'

Structures Monitoring and the Inservice Inspection-ASME Section Xl, Subsection IWL

Programs for the containment dome and wall, as well as the exhaust dorme and duct

component types. On the basis that the programs that manage the aging of these components

(same materials and environments) are consistent with the GALL Report, the staff finds this to

be acceptable.

In the LRA, the applicant stated that it manages reinforced concrete protected from the weather

using the Structures Monitoring Program for the containment operating deck, the'crane wall

(upper), ice condenser end walls, fuel transfer canal walls and floodup overflow structure, lower

containment concrete walls and floor slabs, reactor cavity missile blocks, regenerative heat

exchanger room walls, and steam generator enclosures. On the basis that the program that

manages the aging of these components (same materials and environments) is consistent with

the GALL Report, the staff finds this to be acceptable.

RAI 3.5.3-1

In the LRA, the applicant stated that it manages the loss of material, cracking, and the change

of material properties of concrete'exposed to borated ice'for ice condenser support slab'and ice

condenser wear slab using the Structures Monitoring Program. The staff could not confirm the

applicability of the precedent cited. By letter dated August 20, 2004, in RAI 3.5.3-1, the staff

asked the applicant to clarify whether the ice condenser support slab and ice condenser wear

slab are accessible for direct monitoring. If not, the staff asked the applicant to'describe

specifically how it will manage the associated aging effects.

By letter dated September 2, 2004, the applicant responded to RAI 3.5.3-1, stating that the ice

condenser wear slab is accessible for inspection (direct monitoring) from' inside the ice

condenser during refueling outages. -The ice condenser support slab is accessible for

inspection (direct monitoring) from below in various rooms within the containment annulus area

(i.e., outside the crane wall).

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-I

On the basis of its review of the response to RAI 3.5.3-1, the staff finds the applicant's

response acceptable because direct monitoring is possible for the ice condenser wear slab and

ice condenser support slab. The staff finds that the applicant has demonstrated that it will

adequately manage the loss of material, cracking, and change of material properties of

concrete exposed to borated ice for the ice condenser support slab and the ice condenser wear

slab using the Structures Monitoring Program, so that the intended functions will be consistent

with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

In the LRA, the applicant stated that it manages cracking and the change in material properties

of elastomers protected from weather for removable gate bulkhead seals using the Structures

Monitoring-Divider Barrier Seal Inspection Program. The staff reviewed this program and

documents its evaluation in Section 3.0.3.3.11 of this SER. The staff finds that this program

adequately manages the cracking aging effect through visual examination of the seal.

However, the staff asked the applicant to identify how it detects changes in material properties.

During the audit, the applicant responded that it meant the phrase "change in material

properties" to include a visual inspection that ensures the absence of apparent deterioration

(cracks or defects). By letter dated April 23, 2004, the applicant reiterated this position in its

clarification to the Structures Monitoring-Divider Barrier Seal Inspection Program question.

Because the applicant addressed cracking separately, and because it did not address material

properties that may affect the performance of seals (e.g., hardening and embrittlement), the

staff did not consider this issue resolved. By letter dated August 20, 2004, in RAI B.1.34-1, the

staff asked the applicant to provide a basis for concluding that degradation (e.g., hardening and

embrittlement) will be apparent before the intended function is challenged. Otherwise, the staff

asked the applicant to provide a technical basis for concluding that the elastomeric divider

barrier will continue to perform its design function despite changes in material properties that

may not be visible.

The staff clarified, in an earlier telephone conversation with the applicant, that the elastomeric

pressure seals in question are the penetration seals installed around containment penetrations

and openings through the divider barrier. The applicant identified that it inspects the main

divider barrier seals and replaces them based on their condition, in accordance with CNP

Technical Specification Surveillance Requirement 4.6.5.9, so that these are not subject to AMR.

Additionally, the applicant identified that it visually inspects the divider barrier personnel access

door and equipment hatch seals before containment closure each outage, in accordance with

CNP Technical Specification Surveillance Requirement 4.6.5.5, so that these are also not

subject to an AMR.

By letter dated September 2, 2004, in its response to RAI B.1.34-1, the applicant stated that it

identified the aging management approach for the divider barrier penetration seals in LRA

Table 3.5.2-1, page 3.5-40, under the component type "removable gate (bulkhead) seals," and

in LRA Table 3.5.2-5, page 3.5-66, under the component type "divider barrier penetration

seals." These elastomeric seals are subject to cracking and change in material properties

aging effects, which results in thermal exposure and ionizing radiation aging mechanisms. The

noteworthy effects of these aging mechanisms are elongation, cracking, swelling, and melting.

Cracking, swelling, and melting are readily identifiable by visual inspection. The applicant

stated that visual inspections would observe these aging effects as abnormalities indicative of

material degradation before aging would challenge the intended function of the seals.

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On the basis of its review of the applicant's response to RAI B.1 .34-1, the staff finds that the

reply is acceptable because visual inspection will adequately monitor changes in material

properties of the penetration divider barrier seals so that the intended functions will be

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

ConclusionOn 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 containrnent'

isolation system components that are not addressed by the GALL Report. The intended

functions will be 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).

3.5.2.3.2 Auxiliary Building

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 in the auxiliary building. The applicant identified the following AMPs that will manage'

the aging effects for the auxiliary building components:

* Boric Acid Corrosion Prevention Program

* Systems Testing Program

* Structures Monitoring-Structures Monitoring Program

* Structures Monitoring-Crane Inspection Program

* Structures Monitoring-Masonry Wall Program

* Water Chemistry Control Program

In Table 3.5.2-2 of the LRA, the applicant summarized the AMRs for the auxiliary building

components and identified which AMRs'it considered to be not consistent with or not addressed

in the GALL Report.

Staff Evaluation

The staff reviewed Table 3.5.2-2 of the LRA, which summarizes the results of AMR evaluations

in the SRP-LR for the auxiliary building component groups;.

In the LRA; the applicant proposed to manage loss of material in the galvanized steel EDG'air

intake niissile shield grating 'exposed to weather using the Structures Monitoring Program. 'The

staff finds that the Structures Monitoring Program is acceptable for managing loss of materialbecause the applicant will perform visual inspections on surfaces for any sign of aging

degradation. On the basis of its review, the staff finds that the applicant has identified the

appropriate aging effect for galvanized steel components in an exposed environment and thus

adequately manages this aging effect. '

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In the LRA, the applicant stated that it identified no aging effects for stainless steel structures

exposed to air, including the new fuel storage racks. The GALL Report does not identify air as

an environment for this structure and material.

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, indoor, or in an

air-conditioned enclosure or room). Wrought austenitic stainless steels and CASS are not

susceptible to significant general corrosion that would affect the intended functions of

components. Therefore, the staff concludes that stainless steel in an air environment that is

protected from weather has no AERMs.

In the LRA, the applicant identified no aging effect for Transite exposed to weather, but it uses

the Structures Monitoring Program to manage its aging. The GALL Report identifies no aging effect for this material and environment. This is consistent with industry experience. On that

basis the staff finds the use of the Structures Monitoring Program to be acceptable.

In the LRA, the applicant stated that it manages reinforced concrete using the Structures

Monitoring Program evaluated in Section 3.0.3.2.12 of this SER. This applies to reinforced

concrete both protected from weather and exposed to weather (above- and below- grade) for

the electrical tunnel, exterior walls above and below grade, floor slabs, the fuel transfer canal,

the foundation, interior walls, internal flood curbs, the main steamline enclosure, the roof, spent fuel pit walls and slab, and the sump. On the basis that the program managing the aging of

these components (same materials and environments) is consistent with the GALL Report, the

staff finds this to be acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant adequately identified the aging effects and the AMPs credited to manage the aging effects for the auxiliary building

components that are not addressed by the GALL Report, so that the intended functions will be

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).

3.5.2.3.3 Turbine Building and Screenhouse

Summary of Technical Information in the Application

In Section 3.5.2.1.3 of the LRA, the applicant identified the materials, environments, and

AERMs subject to aging in the turbine building and screenhouse. The applicant identified the

following programs that manage the AERMs for the turbine building and screenhouse

components:

* Structures Monitoring-Structures Monitoring Program

* Structures Monitoring-Masonry Wall Program

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In Table 3.5.2-3 of the LRA, the applicant summarized the AMRs for the turbine building and

screenhouse components and identified which AMRs it considered to be not consistent with or

not addressed in the GALL Report.

Staff Evaluation

The staff reviewed Table 3.5.2-3 of the LRA, which summarizes the results of AMR evaluations

in the SRP-LR for the turbine building and screenhouse component groups.

In the LRA, the applicant stated that it manages the loss of material for galvanized steel

components, including intake corrugated piping and screenhouse forebay bar grille and base,

exposed to raw water, using the Structures Monitoring Program. The staff finds that galvanized

steel components in a raw-water outdoor environment are susceptible to the loss of material.

On the basis of industry operating experience of galvanized steel components exposed to a

raw-water outdoor environment, the staff finds that the loss of material is an applicable aging

effect and is adequately managed by the Structures Monitoring Program.

In the LRA, the applicant stated that it manages reinforced concrete both protected from

weather and exposed to weather (above and below grade) using the Structures Monitoring

Program for the 12-inch concrete wall, essential motor control center walls, the ESW pump

room, the AFW pump room (walls, floor, and ceiling), foundation mat (turbine building)

screenhouse exterior walls (above grade), and the superstructure steel column concrete

encasing. On the basis that the program that manages the aging of these components (same

materials and environments) is consistent with the GALL Report, the staff finds this to be

acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant adequately identified the aging

effects and the AMPs credited to manage the aging effects for the turbine building and

screenhouse components that are not addressed by the GALL Report, so that the intended

functions will be 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).

3.5.2.3.4 Yard Structures

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 subject to aging for the yard structures components. The applicant identified the

following program that manages the AERMs for the yard structures components:

Structures Monitoring-Structures Monitoring Program

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In Table 3.5.2-4 of the LRA, the applicant summarized the AMRs for the yard structures

components and identified which AMRs it considered to be not consistent with or not

addressedthe GALL Report.

Staff Evaluation

The staff reviewed Table 3.5.2-4 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the yard structures groups.

In the LRA, the applicant stated that it manages the loss of material for the galvanized steel

tower, Unit 2 power delivery structure (exposed to weather) using the Structures Monitoring

Program. The staff finds that galvanized steel structures in outdoor environments are

susceptible to loss of material. On the basis of industry operating experience of galvanized

steel structures exposed to an outdoor environment, the staff finds that the loss of material is

an applicable aging effect, which the Structures Monitoring Program adequately manages.

In the LRA, the applicant stated that it manages reinforced concrete exposed to weather (above

and below grade) using the Structures Monitoring Program for the FP pump house walls and

foundation, gas bottle storage tank foundation, roadway, security diesel generator room,

switchyard control house, tank area pipe tunnel (condensate storage, refueling water storage,

and EDG piping tunnel), RWST foundation, CST foundation, FP water storage tank foundation,

PW storage tank foundation, Unit 1 power delivery to switchyard tower, startup transformer

pedestals, and the trench from switchyard to startup transformers (duct bank). On the basis

that the program that manages the aging of these structures (same material and environments)

is consistent with the GALL Report, the staff finds this to be acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant adequately identified the aging

effects and the AMPs credited with managing the aging effects for the yard structures

components that are not addressed by the GALL Report, so that the intended functions will be

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).

3.5.2.3.5 Structural Commodities

Summary of Technical Information in the Application

In Section 3.5.2.1.5 of the LRA, the applicant identified the materials, environments, and

AERMs subject to aging for the structural commodities. The applicant identified the following

programs that manage the AERMs for the structural commodities components:

* Boric Acid Corrosion Prevention Program

* Containment Leakage Rate Testing Program

* Fire Protection Program

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* Inservice Inspection-ASME Section Xl, Subsection IWE Program

* Inservice Inspection-ASME Section Xl, Subsection IWF Program

* Structures Monitoring-Structures Monitoring Program

* Structures Monitoring-Crane Inspection Program

* Structures Monitoring-Divider Barrier Seal Inspection Program

* Water Chemistry Control Program

In Table 3.5.2-5 of the LRA, the applicant summarized the AMRs for the structural commodities

components and identified which AMRs it considered to be not consistent with or not addressed

in the GALL Report.

Staff Evaluation

The staff reviewed Table 3.5.2-5 of the LRA, which summarized the results of AMR evaluations

in the SRP-LR for the structural commodities groups.

The staff evaluated all other AMRs assigned to it in LRA Tables 3.5.2-1 through 3.5.2-5. The

staff finds them to be acceptable.

In the LRA, the applicant stated that it manages the loss of material for galvanized steel

components, including base plates, embedded unistrut, cable trays, and conduits (exposed to

weather) using the Structures Monitoring Program. The staff finds that galvanized steel

components in an outdoor environment are susceptible to the loss of material. On the basis of

industry operating experience of galvanized steel components exposed to an outdoor

environment, the staff finds that the loss of material is an applicable aging effect, which the

Structures Monitoring Program adequately manages.

In the LRA, the applicant stated that it manages the loss of material for aluminum roof flashing

exposed to weather using the Structures Monitoring Program. On the basis of its review, the

staff finds that the applicant has identified the appropriate aging effects for the materials and

environments associated with roof flashing.

In the LRA, the applicant stated that it manages the loss of material for the carbon steel

equipment hatch and personnel access openings threaded fasteners (protected from weather)

using the Inservice Inspection-ASME Section Xl, Subsection IWE and Containment Leakage

Rate Testing Programs. On the basis that the programs that manage this aging effect are

consistent with the GALL Report for the same material and environment, the staff finds that the

applicant adequately manages this component type.

In the LRA, the applicant stated that it manages cracking and the loss of material for stainless

steel SFP fasteners exposed to borated water using the Water Chemistry Control-Primary and

Secondary Water Chemistry Control Program. -The staff reviewed this program and documents

its'evaluation in Section 3.0.3.2.15 of this SER. Based on its review and industry operating

experience, the staff finds the aging effects to be acceptable, and the program is adequate to

manage them.

In the LRA, the applicant identified no aging effect for Transite exposed to weather, but it used

the Structures Monitoring Program to manage aging. On the basis of industry experience with

this material, the staff finds it acceptable to use the Structures Monitoring Program.

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In the LRA, the applicant stated that it manages reinforced concrete, both protected from and

exposed to weather, using the Structures Monitoring Program for flood curbs, hatches, support

pedestals, and trenches (for pipe and cable). On the basis that the program that manages the

aging of these SCs (same materials and environments) is consistent with the GALL Report, the

staff finds this to be acceptable.

RAI 3.5.3-2

In the LRA, the applicant stated that it manages pyrocrete protected from weather using the

Fire Protection Program. The staff reviewed this program and documents its evaluation in

Section 3.0.3.2.5 of this SER. During the audit, the staff noted that separation, cracking, and

loss of material are applicable aging effects for pyrocrete. By letter dated August 20, 2004, in

RAI 3.5.3-2, the staff asked the applicant to identify how the Fire Protection Program manages

the aging effects of separation, cracking, and loss of material, or justify why these aging effects

are not applicable.

By letter dated September 2, 2004, in its response to RAI 3.5.3-2, the applicant stated that

during the Fire Protection Program inspections, it monitors pyrocrete by visual inspection for

obvious degradation such as flaking, cracking, separation, and loss of material.

On the basis of its review of the applicant's response to RAI 3.5.3-2, the staff finds that the

applicant will adequately manage the aging effects of flaking, cracking, separation, and loss of

material using the Fire Protection Program so that the intended functions will be consistent with

the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

In the LRA, the applicant stated that it manages cracking and the change of material properties

for elastomers of the building pressure boundary sealant, floor plugs, and penetration seals

protected from weather using the Structures Monitoring Program. The staff finds the

applicant's approach to evaluating the applicable aging effects for elastomers in structures

outside the containment to be reasonable and acceptable. The staff concludes that the

applicant properly identified the aging effects for elastomers in these structures.

In the LRA, the applicant stated that it manages cracking and the change in material properties

of the divider barrier penetration seal elastomers (protected from weather) using the Structures

Monitoring-Divider Barrier Seal Inspection Program. The staff reviewed this program and

documents its evaluation in Section 3.0.3.3.11 of this SER. In addition, in the LRA, the

applicant proposed to manage changes in material properties by visual examination. The staff

asked the applicant to further justify how a visual examination can detect changes in material

properties.

By letter dated August 20, 2004, in RAI B.1.34-1, the staff asked the applicant to provide a

basis for concluding that degradation (e.g., hardening and embrittlement) will be apparent

before the intended function is challenged. Otherwise, the staff asked the applicant to provide

a technical basis for concluding that the elastomeric divider barrier will continue to perform its

design function despite changes in material properties that may not be visible.

The staff clarified, in an earlier telephone conversation with the applicant, that the elastomeric

pressure seals in question are the penetration seals installed around containment penetrations

and openings through the divider barrier. The applicant identified that it inspects the main

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divider barrier seals and replaces them based on their condition in accordance with CNP

Technical Specification Surveillance Requirement 4.6.5.9, so that-these are not subject to AMR.

Additionally, the applicant identified that it visually inspects the divider barrier personnel access

door and equipment hatch seals before containment closure each outage, in accordance with

CNP Technical Specification Surveillance Requirement 4.6.5.5, so that these are also not

subject to an AMR.

By letter dated September 2, 2004, in its response to RAI B.1.34-1, the applicant stated that it

identified the aging management approach for the divider barrier penetration seals in LRA

Table 3.5.2-1, page 3.5-40, under the component type "removable gate (bulkhead) seals," and

in LRA Table 3.5.2-5, page 3.5-66, under the component type "divider barrier penetration

seals." These elastomeric seals are subject to cracking and change in material properties

aging effects, which result in thermal exposure and ionizing radiation aging mechanisms. The

noteworthy effects of these aging mechanisms are elongation, cracking, swelling, and melting.

Cracking, swelling, and melting are readily identifiable by visual inspection. The applicant.

stated that visual inspections would observe these aging effects as abnormalities indicative of

material degradation before aging would challenge the intended function of the seals.

On the basis of its review of the response to RAI B.1.34-1, the staff finds that the applicant's

response is acceptable because visual inspection will adequately monitor changes in material

properties of the penetration divider barrier seals so that the intended functions will be

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

In the LRA, the applicant stated that it manages the joint elastomer at seismic gaps protected'

from weather using the Structures Monitoring Program. During the audit, the staff asked the

applicant to justify the basis for its conclusion that the elastomer will not harden. The applicant

responded that the function of this elastomer is to prevent debris from entering the gap.

Degradation by hardening of joint elastomer at seismic gaps would not prevent the seismic gap

from performing its intended function. On the basis that the Structures Monitoring Program will

detect the absence of elastomer material, the staff finds that the Structures Monitoring Program

adequately manages aging of the joint elastomer at seismic gaps.

In the LRA, the applicant stated that it manages cracking and change of material properties for

roof elastomers exposed to the weather using the Structures Monitoring Program. The staff

finds that the applicant's approach for evaluating the applicable aging effects for elastomers in

structures outside the containment to be reasonable and acceptable. The staff concluded that

the applicant properly identified the aging effects for elastomers in these structures.

The staff reviewed all other AMRs in Tables 3.5.2-1 through 3.5.2-5 of the LRA. The staff finds

them to be acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant adequately identified the aging

effects and the AMPs credited to manage the aging effects for the structural commodities

components that are not addressed by the GALL Report. The intended functions will be

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).

3.5.3 Conclusion

The staff concludes that the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the structures and component supports, as well as

the commodity groups that are within the scope of license renewal and subject to an AMR, so

that the intended functions will be consistent with the CLB for the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.6 Aging Management of Electrical and Instrumentation and Controls

This section of the SER documents the staff's review of the applicant's AMR results for the

electrical and instrumentation and control (I&C) components associated with the following commodity groups:

* insulated cables and connections

* switchyard bus

* high-voltage insulators

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

I&C components listed in Table 3.6-1 of the LRA. The applicant also listed the materials,

environments, AERMs, and AMPs associated with each commodity group.

In Table 3.6-1, "Summary of the Aging Management Programs for the Electrical Components Evaluated in Chapter VI 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 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.

3.6.2 Staff Evaluation

The staff reviewed Section 3.6 of the LRA to understand the applicant's review process and to

determine whether the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the electrical and l&C components that are within

the scope of license renewal and subject to an AMR. This will verify 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 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 verify that the material

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presented in the LRA is applicable and that the applicant identified the appropriate GALL AMRs.

Section 3.6.2.1 of this SER summarizes the staff's audit findings.

The staff also audited those AMRs that are consistent with the GALL Report and for which

further evaluation is recommended. The staff verified that the applicant's additional

evaluations are 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.

Section 3.6.2.3 contains the staff's evaluation of AMRs that are specific to the electrical and

l&C components. This section also contains evaluation of the adequacy of aging management

for components in each system in electrical and l&C system group. The review included

evaluating whether the applicant identified all plausible aging effects and listed aging effects

that are appropriate for the combination of materials and environments specified.

The staff conducted a technical review of the remaining AMRs that were not consistent with or

addressed by the GALL Report. The review included evaluating whether the applicant identified

all plausible aging effects and listed the appropriate aging effects for the combination of

materials and environments specified. Section 3.6.2.3 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

electrical and l&C components.

Table 3.6-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.6 that are addressed in the GALL Report.

Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls Components

in the GALL Report

Coponent . Aging Effec ' AMPInGALL- -- '-AMP In LRA. Staff Evaluation

Group -. Mechanism .. - Report : -_:,_-_-__::__.

Electrical Degradation due to Environmental TLAA Consistent with

equipment subject various aging qualification of GALL, which

to 10 CFR 50.49 mechanisms electric components recommends further

EQ requirements evaluation (See

(Item Number Section 3.6.2.2.1)

3.6.1-1) . .

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Cormponent Aging Effect/ AMP in GALL AMP InLRA Staff Evaluation,-

Group : Mechanism Report - -

Electrical cables Embrittlement, AMP for electrical Non-EQ Insulated Consistent with

and connections cracking, melting, cables and Cables and GALL, which

not subject to discoloration, connections not Connections recommends no

10 CFR 50.49 EQ swelling, or loss of subject to Program (B.1.22) further evaluation

requirements (Item dielectric strength 10 CFR 50.49 EQ (See Section

Number 3.6.1-2) leading to reduced requirements 3.6.2.1)

insulation resistance;

electrical failure

caused by thermal/

thermoxidative

degradation of

organics, radiolysis

and photolysis

(ultraviolet- sensitive

materials only) of

organics; radiationinduced oxidation;

moisture intrusion

Electrical cables Embrittlement, AMPs for electrical Non-EQ Consistent with

used in cracking, melting, cables used in Instrumentation GALL, which

instrumentation discoloration, instrumentation Circuits Test recommends no

circuits not subject swelling, or loss of circuits not subject Review Program further evaluation

to 10 CFR 50.49 dielectric strength to 10 CFR 50.49 (B.1.21) (See Section

EQ requirements leading to reduced EQ requirements 3.6.2.1)

that are sensitive insulation resistance;

to reduction in electrical failure

conductor caused by thermal/

insulation thermoxidative

resistance (Item degradation of

Number 3.6.1-3) organics; radiationinduced oxidation;

moisture intrusion

Inaccessible Formation of water AMP for Non-EQ Consistent with

medium voltage trees; localized inaccessible Inaccessible GALL, which

(2 kV to 15 kV) damage leading to medium-voltage Medium-Voltage recommends no

cables not subject electrical failure cables not subject Cable Program further evaluation

to 10 CFR 50.49 (breakdown of to 10 CFR 50.49 (8.1.20) (See Section

EQ requirements insulation) caused by EQ requirements 3.6.2.1)

(Item Number moisture intrusion

3.6.1-4) and water trees

Electrical Corrosion of Boric acid corrosion Boric Acid Consistent with

conductors not connector contact prevention Corrosion GALL, which

subject to surfaces caused by Prevention Program recommends no

10 CFR 50.49 EQ intrusion of borated (B.1.4) further evaluation

requirements that water (See Section

are exposed to 3.6.2.1)

borated water

leakage (Item

Number 3.6.1-5)

The staff's review of the electrical and l&C components followed one of several approaches.

One approach, documented in Section 3.6.2.1 of this SER, involves the staff's review of the

AMR results for the electrical and l&C components that the applicant indicated are consistent

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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 the electrical and

l&C components 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 review of the AMR results for the electrical and l&C components 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 aging effects of the structures and component supports.

3.6.2.1 Aging Management Evaluations That Are Consistent with the GALL Report, for Which

No Further Evaluation Is Required

Summary of Technical Information in the Application

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 I&C components:

* -Boric Acid Corrosion Prevention Program

* Non-EQ Inaccessible Medium-Voltage Cable Program

* Non-EQ Instrumentation Circuits Test Review 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 the

alignment of the information in the tables with the information in the GALL Report. The staff

audited those AMRs with notes A through E, where applicable, which indicate that the AMR is

consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the.

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,-

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that 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

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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

verify consistency with the GALL Report. The staff also determined whether the AMR line item

of the different component is applicable 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

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component is applicable to the component under review. The staff verified whether 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 the applicant has credited a different AMP. 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 information provided in the LRA and program

basis 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

consistent with the GALL Report, are indeed consistent with the AMRs in the GALL Report.

Therefore, the staff finds that the applicant identified the applicable aging effects and that they

are appropriate for the combination of materials and environments listed.

3.6.2.1.1 Non-EQ Inaccessible Medium-Voltage Cable

Summary of Technical Information in the Application

Table 3.6.1 of the LRA presents the AMR results for non-EQ inaccessible medium-voltage

cables. The applicant used the GALL Report format to present its AMR of inaccessible

medium-voltage cables requiring aging management.

The applicant identified the following aging effects for non-EQ inaccessible medium-voltage

cables:

* formation of water trees

* localized damage leading to electrical failure (breakdown of insulation) caused by

moisture intrusion and water trees

The applicant credited the Non-EQ Inaccessible Medium-Voltage Cable Program with

managing the identified aging effects for non-EQ inaccessible medium-voltage cables.

A description of the AMP appears in Appendix B to the LRA.

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Staff Evaluation

The staff reviewed the information in LRA Table 3.6.1 for non-EQ inaccessible medium-voltage

cables. On the basis of its review, the staff concludes that the aging effects identified for the

aforementioned cables are consistent with the aging effects evaluated in the GALL Report and

are therefore acceptable.

The staff also reviewed the AMP presented in Section B.1.20 of Appendix B to the LRA, which

is credited with managing the effects for non-EQ inaccessible medium-voltage cables. The

applicant stated that the Non-EQ Inaccessible Medium-Voltage Cable Program (CNP AMP

B.1.20) will apply to non-EQ inaccessible medium-voltage cables and will be consistent with

GALL AMP XL.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49

Environmental Requirements."

The staff reviewed seven program elements contained in the AMP and associated bases

documents against GALL AMP XL.E3 for consistency.

RAI 3.6-3

In a letter dated May 6, 2004, the staff issued RAI 3.6-3, requesting the applicant to clarify the

following:

In response to an audit team's question on inaccessible medium voltage cables

within the scope of license renewal that are exposed to significant moisture

simultaneously with applied voltage, it was stated that the AMP for inaccessible

medium voltage cables will test the cables as well as inspect for water in the

manholes. It was also stated that inspection of water in the manholes associated

with the GALL XL.E3 AMP would be performed every 10 years. The frequency to

inspect for water in manholes every ten years may be too long. Justify the

frequency of inspecting manholes for water every 10 years. In addition, provide

your current criteria for inspecting manholes for water.

In a letter dated June 8, 2004, the applicant stated that the Non-EQ Inaccessible

Medium-Voltage Cable Program will be consistent with GALL AMP XI.E3. GALL AMP XI.E3,

Section 2, states the following:

Periodic actions are 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. Medium-voltage cables for which such actions

are taken are not required to be tested since operating;experience indicates that

prolonged exposure to moisture and voltage are required to induce this aging

mechanism.

This section implies that if periodic actions are not taken to prevent cable

exposure to significant moisture, testing is required. The Non-EQ Inaccessible

Medium-Voltage Cable Program will require testing of all cables included in the

program. The frequency of inspections for water is relevant only if it provides

reasonable assurance that the cables are not exposed to significant moisture

and therefore do not require testing. Since testing is to be performed regardless

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of inspection results, the inspection frequency is not relevant. The proposed

testing frequency in the AMP is consistent with GALL AMP XL.E3 for cables that

are exposed to significant moisture.

The staff concludes that, since the Non-EQ Inaccessible Medium-Voltage Cable Program will

require testing of all cables included in the program, the above response is acceptable.

Therefore, the staff's concerns described in RAI 3.6-3 are resolved.

RAI 3.6-4

The staff was also concerned about inaccessible medium-voltage cables that run in sealed

conduits from transformers TR201 AB to bus 2A which are not subject to any AMP. In a letter

dated May 6, 2004, the staff issued RAI 3.6-4 asking the applicant to clarify the following:

In response to audit team's question on inaccessible medium voltage cables, it

was stated that the cables from transformer TR 201 AB to bus 2A run in conduits

that are sealed on both ends and have been inspected for water and that the

lack of water precludes any aging mechanisms on the cables that would make

them subject to an AMP. It is not clear to the staff how often these seals are

inspected for water damage and how often they are replaced. An AMP would be

needed to assure that the seals remain intact to prevent intrusion of water in the

conduits. Please provide a description of the AMP that will be relied upon to

require periodic inspections of these seals or provide justification for not having

an AMP. In addition, describe how the cables from (1) start-up transformers TR

201 CD, 101 AB, and 101 CD to the safety buses and (2) from transformers TR4

and TR5 to the start-up transformers, are routed.

In a letter dated June 8, 2004, the applicant responded that it previously determined the cables

associated with the sealed conduits are not subject to aging effects, because they are not

exposed to significant moisture. The applicant stated, however, that it will add these cables to

the list of those subject to GALL AMP XL.E3. Consistent with the response to RAI 3.6-3, the

applicant will test all of the cables included in LRA Section B.1.20. These cables will not require

inspection for the presence of significant moisture. Therefore, inspection of the seals will not be

relevant since the cables will be tested. An AMP for conduit seal inspections is not required.

With regard to the routing of cables from the transformers to the safety buses, the applicant

stated that a combination of switchyard bus and insulated feeder cables, which are not installed

underground, connect the Unit 1 reserve auxiliary transformers, TRIOIAB and TR101CD, and

safety buses 1 A, 1 B, 1 C, and 1 D. Cables in underground conduits encased in a duct bank

which is sealed on both ends connect the Unit 2 reserve auxiliary transformers, TR201AB and

TR201 CD, and safety buses 2A, 26, 2C, and 2D.

Based on the above, the staff concludes that the addition of cables in underground conduits to

the list of cables subject to GALL AMP XL.E3 testing requirements satisfies its concern.

Therefore, the staff's concerns described in RAI 3.6-4 are resolved.

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RAI 3.6-5

The staff also reviewed the UFSAR Supplements for the AMPs credited with managing aging in

electrical and l&C system components to determine whether the program descriptions are

adequate. In a letter dated May 6, 2004, the staff issued RAI 3.6-5, stating that the UFSAR

Supplement description in the LRA for the non-EQ cable AMPs does not adequately describe -

the program, as required by 10 CFR 54.21 (d). The description of the UFSAR Supplement for

aging management of electrical and l&C components should be consistent with Table 3.6-2 of

the SRP-LR. The staff asked the applicant to submit a revised UFSAR Supplement that is

consistent with SRP-LR to satisfy 10 CFR 54.21 (d).

In letters dated June 8 and September 2, 2004, the licensee submitted revised program

descriptions for UFSAR Supplements for the AMPs credited with managing aging in electrical

and l&C system components. However, the revised UFSAR Supplement for GALL AMP XL.E2

does not describe the AMP that will manage those instrument cables that are disconnected

during instrument calibration.

By letter dated October 18, 2004, the applicant stated that it will include testing of

instrumentation cables that are disconnected during calibration and revised the Non-EQ

Instrumentation Circuits Test Review Program description for the UFSAR as follows:

The Non-EQ Instrumentation Circuits Test Review Program will manage aging

effects for electrical cables that:

1. Are not subject to the environmental qualification requirements of

10 CFR 50.49, and

2. Are used in instrumentation circuits with sensitive, high-voltage, low-level

signals exposed to adverse localized environments caused by heat, radiation,

or moisture.

An adverse localized environment is defined as being significantly more severe

than the specified service environment for the cable. This program will detect

aging effects by reviewing calibration or surveillance results for components

within the program scope. A proven cable test for detecting insulation

deterioration on in-scope instrumentation cables that are disconnected during

calibration will be performed at a frequency determined by engineering

evaluation, but will not be less than once per ten years. The Non-EQ

Instrumentation Circuits Test Review Program will be implemented prior to the

period of extended operation.

This is Commitment # 13 in Appendix A of this SER.

Based on its review, the staff concludes that the revised UFSAR Supplements provide an

adequate summary description of the revised non-EQ cable AMPs and are acceptable.

Therefore, the staff's concern described in RAI 3.6-5 is resolved.

The staff conducted an audit of the information provided in the LRA and program basis

documents, which are available at the applicant's engineering office. On the basis of its audit,

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the staff finds that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are indeed consistent with the AMRs in the GALL Report. Therefore, the staff finds that

the applicant identified the applicable aging effects and that 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 it will

adequately manage the effects of aging so that the intended functions will be 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 concludes that the applicant adequately identified the aging

effects, and the AMPs credited with managing the aging effects, for inaccessible mediumvoltage cables. Therefore, the intended functions will be 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 given in the applicant's revision dated October 18, 2004,

adequately describes the AMPs credited with managing aging in these components, as

required by 10 CFR 54.21 (d).

3.6.2.1.2 Staff RAls Pertaining to Recent Operating Experience and Emerging Issues

Because the NRC issued the GALL Report and SRP-LR 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 issued RAls to determine how the applicant proposes to address these items for license

renewal. The following documents the applicant's responses to these RAls and the staff's

evaluations of the responses.

Staff Evaluation

The NRC issued proposed ISG-15,"Revision of Generic Aging Lessons Learned (GALL) Aging

Management Program (AMP) XL.E2, 'Electrical Cables Not Subject to 10 CFR 50.49

Environmental Qualification Requirements Used in Instrumentation Circuits,"' to incorporate

lessons learned since the GALL Report was first issued. The current GALL AMP XI.E2 relies

on a routine calibration test performed as part of plant technical specification requirements to

identify the existence of aging degradation for the electrical cables used in radiation monitoring

and nuclear instrumentation circuits. For those plants for which technical specification

requirements do not require calibration testing of the instrumentation loops, this revision

provides that an applicant may use a proven cable test for detecting deterioration of the

insulation system (such as insulation resistance tests, time-domain reflectometry tests, or other

testing judged to be effective in determining cable insulation condition).

The CNP program for the management of aging effects of electrical cables not subject to

10 CFR 50.49 requirements used in instrumentation circuits will be the Instrumentation Circuit

Test Review Program. This program will be consistent with, but include the following exception

to, GALL AMP XL.E2:

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Rather than perform the reviews at normal calibration frequency specified in the

Technical Specifications,'the first reviews will be performed before the period of

extended operation and every 10 years thereafter. Calibrations or surveillances

that fail the acceptance criteria will be reviewed at the time of the calibration or

surveillance.

The staff concludes that the above program is consistent with proposed ISG-15.

RAI 3.6-2

In a letter dated May 6, 2004, the staff issued RAI 3.6-2:

With regard to non-EQ cables sensitive to a reduction in insulation resistance,

please confirm consistency with the proposed ISG-15, Revision of Generic Aging

Lessons Learned (GALL) Aging management Program (AMP) XL.E2,"Electrical

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Used in Instrumentation Circuits."

In a letter dated June 8, 2004, the applicant responded to RAI 3.6-2, stating the following:

The'exception to NUREG-1 801, Section XL.E2, in LRA Appendix B,

Section B.1.21, states that, 'The first reviews will be performed before the period

of extended operation and every 10 years thereafter. Calibrations or

surveillances that fail to meet the acceptance criteria will be reviewed at the time

of the calibration or surveillance." The intent of this exception is in agreement with

the mark-up of ISG-1 5 provided to the NRC in the referenced NEI letter dated

December 15, 2003. The NRC has not yet issued a formal response to these

industry'comments. Therefore, it is the intent of this program to be consistent with

NUREG-1 801, Section X1.E2 with the stated exception, which is consistent with the

draft of ISG-15 provided in the referenced NEI letter. Other elements of the Non-EQ

Instrumentation Circuits Test Review Program are consistent with ISG-1 5.

In addition, the staff asked the applicant if any instrumentation cables at CNP are disconnected for

the purpose of instrument calibration. By letter dated October 18, 2004, the applicant-responded by

stating the following:

CNP has instrumentation cables within the scope of the Non-EQ Instrumentation*'

Circuits Test Review Program that are disconnected during calibration. The current

method for detecting deterioration of the insulation on instrumentation cables uses

time-domain reflectometry (TDR). A proven cable test, such as TDR, will be

conducted during the period of extended operation as part of the Non-EQ

Instrumentation Circuits Test Review Program. The test frequency of

instrumentation cables that are in the scope of this program, but are disconnected

during calibration, shall be determined by l&M based on engineering evaluation, but

will not be less than once per ten years. The test method selected by l&M is

consistent with the proposed ISG-15 revision issued on August 12, 2003, NEI

comments provided in the December 15, 2003, letter and the previously approved

NRC Staff position documented in NUREG-1785, License Renewal Safety

Evaluation Report for the H. B. Robinson Steam Electric Plant, Unit 2 [Accession

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L

No. ML040200981]. NUREG-1785, Section 3.6.2.3.2.2, discusses performing

testing every 10 years for sensitive instrumentation circuits that are disconnected

during calibration and are not part of the calibration program. The NRC Staff found

testing acceptable because such testing would determine potential cable

degradation, and the 10-year frequency was determined to be acceptable because

cable insulation degradation is a slow process, plant-specific operating experience

did not identify previous cable degradation, and this frequency is consistent with the

NUREG-1 801 cable aging management programs. A review of CNP operating

experience found no age-related failures for the high-range radiation or the neutron

monitoring cables. The only industry operating experience identified for these cables

was Westinghouse Technical Bulletin 86-01, which was not applicable to CNP,

because the cable insulation material at CNP is different than that discussed in the

bulletin. This plant operating experience demonstrates that these cables have

operated over long periods without a loss of intended function. Therefore, the

Non-EQ Instrumentation Circuits Test Review Program, which will include testing of

instrumentation cables that are disconnected during calibration, will provide

adequate management of the aging effects for instrumentation cables.

On the basis of the applicant's responses to RAI 3.6-2, the staff concludes that the applicant's

commitment to use the Instrumentation Circuit Test Review Program, which will be consistent with

the draft ISG-15, to manage the aging effects of electrical cables not subject to 10 CFR 50.49

requirements is acceptable. Therefore, the staff's concerns described in RAI 3.6-2 are resolved.

This is Commitment # 38 in Appendix A of this SER .

Conclusion

The staff has verified the applicant's claim of consistency with the GALL Report. The staff has 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 it will adequately manage the effects of aging for these

components so that their intended functions will be consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

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

Recommended

Summary of Technical Information in the Application

In 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 aging effects through the following two programs:

* Electrical Equipment Subject to Environmental Qualification Program

* Quality Assurance for Aging Management of Nonsafety related Components Program

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

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reviewed the applicant's evaluation to determine whether it adequately addresses the issues that

were further evaluated. 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 audit and review report contains details of

this effort.

For some line items consistent with the GALL Report in LRA Table 3.6.2-1, the GALL Report

recommends further evaluation. In cases where the GALL Report recommends further evaluation,

the staff reviewed these additional evaluations provided in LRA Section 3.6.2.2 against the criteria

provided in SRP-LR Section 3.6.2.2. Line items requiring no further evaluation are within the scope

of the staff evaluation.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

Environmental qualification is a TLAA as defined in 10 CFR 54.3. The TLAAs must be evaluated in

accordance with 10 CFR 54.21 (c)(1). The staff reviews the evaluation of this TLAA separately in

Section 4.4 of this SER, following the guidance in Section 4.4 of the SRP-LR.

The staff reviewed Table 3.6.2-1 of the LRA, which summarizes the results of AMR evaluations in

the SRP-LR for the electrical component groups. All items within the scope are consistent with the

GALL Report.

Conclusion

On the basis of its review, the staff finds that the applicant's further evaluations conducted in

accordance with the GALL Report are consistent with the acceptance criteria 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 it will adequately manage the effects of aging so that the intended.

functions will be consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.6.2.2.2 Quality Assurance for Aging Management of Nonsafety related Components

The applicant implements site QA procedures, review and approval processes, and administrative

controls in accordance with the requirements of Appendix B to 10CFR Part 50. The CNP Quality

Assurance Program applies to both safety related and nonsafety related SCs. Section 3.0.4 of this

SER provides the staff evaluation of this program.

Conclusion

On the basis of its audit, the staff finds that the applicant's further evaluation conducted in

accordance with the GALL Report is consistent with the acceptance criteria in Section 3.6.2.2 of the

SRP-LR.

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

Report

In LRA Table 3.6.2-1, the staff reviewed additional details of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with or are not addressed in the GALL

Report. The staff evaluation of the electrical and l&C component AMPs that are not consistent with

or are not addressed in the GALL Report appears below.

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3.6.2.3.1 High-Voltage Insulators

Summary of Technical Information in the Application

Table 2.5.1, "Electrical and Instrumentation and Control Systems Components Subject to Aging

Management Review," of the LRA, identifies high-voltage insulators as a component within the

scope of license renewal. Table 3.6.2-1, "Electrical Components, Summary of Aging Management

Evaluation," of the LRA, does not list any aging effects associated with high-voltage insulators.

Staff Evaluation

The staff reviewed Section 4.5 of CNP LRP-EAMR-01, 'Aging Management Review for Electrical

Systems," which discusses aging effects for high-voltage insulators. The aging effects identified for

high-voltage insulators requiring evaluation include the following:

* surface contamination

* cracking and loss of material

The report identifies various airborne materials such as dirt, salt, and industrial effluents that can

contaminate insulator surfaces. The buildup of surface contamination is gradual, and in most areas,

rain can wash away such contamination. The glazed insulator surface aids this contamination

removal.

The loss of material or cracking due to mechanical wear is an aging effect for strain and suspension

insulators if they are subject to significant movement. Movement of the insulators can result from

wind blowing the supported transmission conductor, causing it to swing from side to side. Although

this mechanism is possible, industry experience has shown that transmission conductors do not

normally swing. When they do, because of a substantial wind, they do not continue to swing for

very long once the wind has subsided. Wind that can cause insulators to vibrate is considered in

the design and installation. Therefore, surface contamination and the loss of material due to wear of

high-voltage insulators are not AERMs for the period of extended operation.

The staff agrees that the LRP-EAMR-01 report correctly identifies the aging effects and AMP

associated with high-voltage insulators.

Conclusion

The staff agrees with the applicant's conclusion that high-voltage insulators do not require a

separate AMP.

3.6.2.3.2 Switchyard Bus

Summary of Technical Information in the Application

Table 2.5.1 of the LRA identifies switchyard bus as a component within the scope of license

renewal. Table 3.6.2-1 of the LRA does not list any aging effects associated with switchyard bus.

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Staff Evaluation

The staff reviewed Section 4.5 of CNP LRP-EAMR-01 which discusses aging effects for switchyard

bus. The aging effects identified for switchyard bus requiring evaluation include the following:

* surface oxidation

* vibration

The report identifies the most prevalent mechanism contributing to aging of an aluminum' bus as

connection surface oxidation, which can lead to increased resistance and heating. 'Oxidation of

switchyard aluminum bus is a very slow-acting aging mechanism. Further, the report states that

operating experience does not identify aging problems with the CNP switchyard bus. The

Preventive Maintenance Program at CNP verifies that No-Ox grease is used on aluminum bus

connections. The application of No-Ox grease precludes oxidation of the aluminum surface at the

bus connections. The grease is checked routinely at CNP during bus maintenance. Therefore, the

oxidation of the switchyard bus is not an aging mechanism that leads to a change in material

properties resulting in increased resistance and heating. Therefore, oxidation of these components

is not an AERM during the period of extended operation at CNP.'

Wind can cause vibration of switchyard bus and insulators, but this is considered in the design and

installation. Therefore, the aging effects of cracking that could be caused by bus vibration do not

require management during the'period of extended operation at CNP.

The staff agrees that the LRP-EAMR-01 report correctly identifies the aging effects and AMP

associated with switchyard bus.

Conclusion

The staff agrees with the applicant that switchyard bus requires no 'separate AMP.

3.6.2.3.3 Fuse Holders

Summary of Technical Information in the Application -

Section 2.1.3 of the LRA states that fuse holders are considered passive electrical components and

are included in the AMR in the same manner as terminal blocks and other types of electrical

connections. Consistent with ISG-5, "Identification and Treatment of Electrical Fuse Holders for

License Renewal," the applicant considered fuse holders that are part of a larger assembly inside

the enclosure of active components to be part of a larger assembly and not'subject to an AMR.

ISG-5 addresses fuse holders that are not part of a larger assembly, but that support safety related

and nonsafety related functions in which a failure of a fuse precludes the performance of a safety

function.

Staff Evaluation

RAI 3.6-1

In LRA Table 3.6.2-1, the staff did not find an AMR of results for fuse holders. In a letter dated May

5, 2004, the staff issued RAI 3.6-1'stating the following:

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In response to audit team's question on fuse holders, you stated that you have

completed an assessment to identify fuse holders that are subject to AMR based on

requirements of license renewal and ISG-5. The assessment identified fuse holders

in scope for license renewal, then screened in fuse holders in-scope based upon

whether (1) they are included in an active component (panels, switchgear, or

cabinet), (2) they perform an intended function to meet the criteria of 10 CFR 54.4(a)

(i.e., isolate safety loads from non-safety loads or are used as protective devices to

ensure the integrity of containment electrical penetrations), or (3) they have bolted

connections, which are not subject to the same aging stressors (i.e., mechanical

stress and fatigue) as spring loaded fuse holder clips; The assessment determined

that fuse blocks are either an active component, do not perform a license renewal

intended function, or have bolted connections. With regard to the fuse holders that

have bolted connections, please address the aging effects due to vibration,

corrosion, and fatigue due to thermal cycling identified in the subject ISG and provide

justification as to why an additional AMP for bolted connection fuse holders is not

required.

By letter dated June 8, 2004, the applicant stated that the CNP AMR of electrical systems eliminates

fuses with bolted connections, since bolted connections do not have the issue associated with

metallic fuse clamps. Bolted connections on fuse holders are subject to the same aging effects as

bolted connections included in the cables and connections commodity group. The CNP AMR

includes bolted connections on fuse holders as connections in the cable and connections

commodity group.

In a meeting on September 1, 2004, the staff contended that GALL AMP XL.E1 does not cover

aging affects related to vibration, corrosion, and fatigue associated with fuse holders with bolted

connections. The applicant stated that based on its review, no fuse holders at CNP are subject to

the aging effects discussed in ISG-5.

The staff concluded that the applicant must confirm that no fuse holders at CNP are subject to the

aging effects discussed in ISG-5. By letter dated October 18, 2004, the applicant confirmed that no

fuse holders at CNP are subject to the aging effects discussed in ISG-5. On this basis, the staff

concern described in RAI 3.6-1 above is resolved.

Conclusion

On the basis of its review and evaluation of the above RAI, the staff concludes that the applicant

adequately identified that no fuse holders at CNP are subject to the aging effects discussed in ISG5.

3.6.2.3.4 Station Blackout Components

Summary of Technical Information in the Application

The License Renewal Rule, Section 10 CFR 54.4(a)(3), requires that, "all systems, structures, and

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

demonstrates compliance with the Commission regulation for SBO (10 CFR 50.63) be included

within the scope of license renewal.' Under the station blackout (SBO) rule, therefore, offsite power

systems provide a means of recovering from the SBO. This meets the criteria in 10 CFR 54.4(a)(3)

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as a system that performs a function that demonstrates compliance with the Commission's

regulations on SBO. For this reason, the staff requires that applicable offsite power system Ses be

included within the scope of license renewal and subject to an AMR, or additional justification for

their exclusion must be provided.

In Section 2.5 of the LRA, the applicant described switchyard components that are relied on to'

support SBO recovery actions. The applicant identified the following components comprising the

offsite power source path that are within the scope of license renewal:

* switchyard circuit breakers feeding the reserve auxiliary transformers

* reserve auxiliary transformers

* circuit breaker-to-transformer and transformer-to-onsite electrical distribution

interconnections

* associated control circuits and structures

Staff Evaluation

RAI2.5-1

In a letter dated May 6, 2004, the staff issued RAI 2.5-1, concerning the switchyard components that

are relied on in safety analyses to perform a function in the recovery from SBO, as follows:

ISG 2, "NRC Staff Position on the License Renewal Rule (10 CFR 54.4) as it Relates

to the Station Blackout Rule (SBO) (10 CFR 50.63)," states, in part, that 'The offsite

power systems consist of a transmission system (grid) component that provides a

source of power and a plant system component that connects that power source to a

plant's onsite electrical distribution system which power safety equipment." For the

purpose of the license renewal rule, the staff determined that the plant system

portion of the offsite power system that is used to connect the plant to the offsite

power source should be included within the scope of the rule. This path typically

includes the switchyard circuit breakers that connect to the offsite system power

transformers (startup transformer), transformers themselves, the intervening

overhead or underground circuits between circuit breaker and transformer and

transformer and onsite electrical distribution system, and the associated control

circuits and structures. In this regard, the portion'of the SBO path indicated on the

offsite power boundary drawing for license renewal does not include the - - -

transmission conductors and connections and the associated control cables from the

first breaker (disconnect) from the 345 kV [kilovolt] and 765 kV.switchyard buses to

the 765 kV/34.5 kV and 345 kV/34.5 kV transformers. Please revise this drawing to

include the above components indicating which components require an aging

management review (AMR).

In a letter dated June 8, 2004, the applicant stated that the portion of the SBO path indicated on

license renewal offsite power boundary drawing 12-LRA-Electricall includes the switchyard circuit

breakers that connect to the offsite system power transformers (startup transformers), the

transformers themselves, and the intervening overhead or underground circuits between circuit

breakers and transformers and between transformers and the onsite electrical distribution system.

Switchyard items credited for the SBO path include the associated control circuits and structures, in

addition to the items shown on the boundary drawing. Further, the path from the switchyard circuit

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breakers that connect to the offsite power system transformers (startup transformers) to the 765-

kV/34.5-kV and 345-kV/34.5-kV switchyard transformers is considered part of the transmission

system (grid), which is not included in the scope of license renewal and is not subject to an AMR.

Therefore, the license renewal offsite power boundary drawing does not require any changes.

RAI 2.5-2

In addition, in a letter dated May 6, 2004, the staff issued RAI 2.5-2, concerning the transmission

conductors that are relied on in safety analyses to perform a function in the recovery from SBO, as

follows:

Table 2.5-1 of the license renewal application (LRA) lists the electrical and

instrumentation and control (I&C) components included in the AMR. This list does

not include transmission conductors, and uninsulated ground conductors listed in the

LRA Table 2.1.1. With regard to transmission conductor and connectors, it is stated

that the transmission conductors have been screened out because they have no

aging effect. Transmission conductors have been known to have loss of conductor

strength. The most prevalent mechanism contributing to the loss of conductor

strength is corrosion, which includes corrosion of steel core and aluminum strand

pitting. Explain why no aging effects related to conductor corrosion have been

identified that would cause a loss of function for the extended period of operation.

Also, explain why no significant aging effects related to wind loading vibration or

sway on high voltage connections has been identified. In addition, provide

justification for excluding uninsulated ground conductors from the AMR.

In a letter dated June 8, 2004, the applicant stated that it screened out the transmission conductors

not because they have no aging effects, but because they do not perform an intended function for

CNP. The credited SBO recovery path for either unit at CNP has no transmission conductors.

Connections of the startup transformers to the offsite power system are through switchyard bus and

underground 34.5-kV insulated cables rather than transmission conductors. The 34.5-kV

underground cables are medium-voltage insulated cables, not transmission conductors.

Transmission conductors perform no license renewal intended function in other CNP applications.

Therefore, this commodity type is not subject to an AMR.

With regard to the uninsulated ground conductors, the applicant stated that the uninsulated ground

conductors do not perform an intended function, and are therefore not subject to an AMR.

On the basis of its review, including the applicant's responses to the RAls, the staff concludes that

the applicant adequately identified and provided an acceptable AMP to manage the aging effects

associated with the components credited in the SBO restoration path.

Conclusion

On the basis of its review, the staff concludes that the applicant adequately identified the aging

effects for the components associated with the SBO restoration path and will have adequate AMPs

for managing the aging effects for these components, such that the intended function of the

components will be consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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3.6.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that it will

adequately manage the effects of aging for the electrical and l&C components that are within the

scope of license renewal and subject to an AMR so that the intended functions will be consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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4. TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging 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 4.7.7. Sections 4.2

through 4.7 of this safety evaluation report (SER) document the staff's review of the TLAAs.

The TLAAs are certain plant-specific safety analyses that are based on an explicitly assumed 40-

year plant life. Pursuant to Title 10, Section 54.21 (c)(1), of the Code of Federal Regulations

(10 CFR 54.21 (c)(1)), the applicant for license renewal 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 and analyses for the Donald C. Cook Nuclear Plant (CNP)

against the six criteria specified in 10 CFR 54.3 to identify TLAAs. The applicant indicated that it

identified the calculations and analyses that meet the six criteria by searching the current licensing

basis (CLB), including the updated final safety analysis report (UFSAR), design-basis documents,

previous license renewal applications, technical specifications, and NUREG-1800, "Standard Review

Plan for Review of License Renewal Applications for Nuclear Power Plants," issued April 2001

(hereafter referred to as the SRP-LR). The applicant listed the following TLAAs in LRA Table 4.1-1,

"List of CNP TLAAs":

* reactor vessel neutron embrittlement, including analyses for upper-shelf energy (USE),

pressurized thermal shock (PTS), and pressure-temperature (P-T) limits

* metal fatigue, including American Society of Mechanical Engineers (ASME) Code Class 1

and non-Class 1, and environmentally-assisted fatigue

* environmental qualification of electrical components

* containment liner plate and penetration fatigue analyses

* concrete containment tendon pretress

* reactor coolant system (RCS) piping leak-before-break

* ASME Code Case-481 (reactor coolant pump casings)

* ice condenser lattice frame

* reactor vessel underclad cracking

* steam generator tubes-flow induced vibration

* fatigue of cranes

Pursuant to 10 CFR 54.21 (c)(2), the applicant listed only one plant-specific exemption based on

TLAA, which exempts CNP, Units 1 and 2, from implementing the requirements of Appendix G,

"Fracture Toughness Requirements," to 10 CFR Part 50 and to instead utilizes ASME Code Case

N-641, "Alternative Pressure-Temrperature Relationship and Low Temperature Overpressure

Protection System Requirements." The applicant stated that it projected the P-T limits evaluations

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for both units to 60 years, and therefore, continuation of the exemption is justified for the period of

extended operation.

4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant identified the TLAAs applicable to CNP, Units 1 and 2, and

discussed exemptions based on TLAAs. The staff reviewed the information to determine whether

the applicant had provided adequate information to meet the requirements of 10 CFR 54.21 (c)(1)

and 10 CFR 54.21 (c)(2).

10 CFR 54.3 defines TLAAs as calculations and analyses that meet the following six criteria:

(1) involve systems, structures, and components within the scope of license renewal, as

delineated in 10 CFR 54.4(a)

(2) consider the effects of aging

(3) involve time-limited assumptions defined by the current operating term, for example, 40

years,

(4) were determined to be relevant by the applicant in making a safety determination

(5) involve conclusions, or provide the basis for conclusions, related to the capability of the

system, structure, and component to perform its intended functions, as delineated in

10 CFR 54.4(b)

(6) are contained or incorporated by reference in the CLB

The applicant listed the TLAAs applicable to CNP in LRA Table 4.1-1, based on the applicant's

review of the potential TLAAs listed in NUREG-1800, Table 4.1-2, "Potential Time-Limited Aging

Analyses,' and Table 4.1-3, "Additional Examples of Plant-Specific TLAAs as Identified in by the

Initial License Renewal Applicants." Table 4.1-1 of the LRA did not include the following topics listed

as applicable to pressurized water reactor (PWR) facilities:

(1) metal corrosion allowance

(2) inservice flaw growth analyses that demonstrate structure stability for 40 years

(3) inservice local metal containment corrosion analyses

(4) high energy line break analysis based on cumulative usage factor

(5) fatigue analysis for the reactor coolant pump (RCP) flywheel

(6) flow-induced vibration endurance limit, transient cycle count assumptions, and ductility

reduction of fracture toughness for the reactor vessel internals (RVls)

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The applicant stated in LRA Section 4.1 that loss of material by corrosion of structural components

related to items 1 and 3 is addressed as part of the AMR processes discussed in LRA Section 3,

and a review of inservice inspection (ISI) records indicated no defects that required analytical;

evaluation bf the component through the end of the operating license (item 2). Further, the

applicant did not postulate HELBs based on fatigue usage (item 4) at CNP because the design of

Class 1 and non-Class 1 piping meets American National Standards Institute (ANSI) B31.1, "Piping

Code." The RCP flywheel fatigue analysis (item 5) assumed a 60-year period of plant operation,

which makes the analyses applicable to the period of extended operation. Although item 6 did not

meet all six criteria for TLAAs, the Reactor Vessel Internals Program, discussed in SER Section

3.0.3.1, addresses ductility reduction of fracture toughness for RVI.

4.1.3 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable list of

TLAAs, as required by 10 CFR 54.21 (c)(1). As required by 10 CFR 54.21 (c)(2), the staff has

confirmed that one 10 CFR 50.12 exemption has been granted on the basis of a TLAA to CNP,

Units 1 and 2, from the requirements of Appendix G to 10 CFR Part 50. The applicant will instead

utilize ASME Code Case N-641.

4.2 Reactor Vessel Neutron Embrittlement

Title 10, Part 50, "Domestic Licensing of Production and Utilization Facilities," of the Code of Federal

Regulations (10 CFR Part 50) provides the following regulations governing reactor vessel integrity:

* Pursuant to 10 CFR 50.60, all light-water reactors must meet the fracture toughness and

material surveillance program requirements for the reactor coolant boundary as set forth in

Appendices G and H to 10 CFR Part 50.

* Pursuant to 10 CFR 50.61, fracture toughness requirements protect against pressurized

thermal shock.

The applicant identified three analyses affected by irradiation embrittlement that were described as

TLAAs. Section 4.2.1, "Charpy Upper-Shelf Energy," Section 4.2.2, "Pressurized Thermal Shock,"

and Section 4.2.3, "Pressure-Temperature Limits," of this SER discuss these analyses.

Neutron embrittlement is a potentially significant aging mechanism for all ferritic materials that have

a neutron fluence of greater than 1 x1 0" n/cm2 (E 2 1.0 million electron volts (MeV)). The relevant

calculations use predictions of the cumulative damage to the reactor pressure vessel (RPV) from

neutron embrittlement and were originally based on a 40-year period of plant operation. The RPV

contains the core fuel assemblies and is made of thick steel plates that are welded together.

Neutrons from the fuel in the reactor irradiate the vessel during operation and change the material

properties of the steel. The most pronounced and significant changes occur in the fracture

toughness material property. Fracture toughness is a measure of the resistance to crack extension

under stresses. Embrittlement is a reduction in this material property resulting from irradiation. The

largest amount of embrittlement usually occurs at the section of the vessel's wall closest to the

reactor fuel, referred to as the vessel's beltline. The embrittlement of the beltline material depends

on its chemical composition, and copper and nickel are the most important chemical elements in

determining how sensitive the steel is to neutron irradiation.

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4.2.1 Charpy Upper-Shelf Energy

The U.S. Nuclear Regulatory Commission (NRC) provides screening criteria for the USE material

property in 10 CFR Part 50, Appendix G. Appendix G requires that RPV beltline materials have

Charpy USE values in the transverse direction for the base metal and along the weld for the weld

material of no less than 102 joules (J) (75 foot-pounds (ft-lb)) initially, and maintain Charpy USE

values throughout the life of the vessel of no less than 68 J (50 ft-lb). However, in accordance with

paragraph IV.A.1.a. of Appendix G to 10 CFR Part 50, Charpy USE values below these criteria may

be acceptable if it is demonstrated, in a manner approved by the Director, Office of Nuclear Reactor

Regulation, that the lower values of Charpy USE will provide margins of safety against fracture

equivalent to those required by Appendix G to Section Xl of the ASME Boiler and Pressure Vessel

(B&PV) Code. Regulatory Guide (RG) 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel

Materials," issued May 1988, provides an expanded discussion regarding the calculation of Charpy

USE values and describes two methods for determining Charpy USE values for RPV beltline

materials, depending on whether or not a given RPV beltline material is represented in the plant's

Reactor Vessel Material Surveillance Program (i.e., the 10 CFR Part 50, Appendix H program). If

surveillance data are not available, the Charpy USE values are determined in accordance with

Position 1.2 in RG 1.99, Revision 2. If two or more surveillance data are available, the Charpy USE

values should be determined in accordance with Position 2.2 in RG 1.99, Revision 2. These

methods refer to Figure 2 in RG 1.99, Revision 2, which indicates that the percentage drop in

Charpy USE values is dependent upon the amounts of copper and the neutron fluence. Because

the analyses performed in accordance with Appendix G to 10 CFR Part 50 are based on a flaw with

a depth equal to one-quarter of the vessel wall thickness (114T), the Charpy USE analysis uses the

neutron fluence at the 1/4T depth location.

4.2.1.1 Summary of Technical Information in the Application

Appendix G to 10 CFR 50 requires that, "Reactor vessel beltline materials must have Charpy uppershelf energy...of no less than 75 ft-lb (102 J) initially and must maintain Charpy upper-shelf energy

throughout the life of the vessel of no less than 50 ft-lb (68 J)...." The applicant originally

documented its analyses of USE for 32 effective full-power years (EFPYs) in its response to NRC

Generic Letter 92-01, Revision 1, "Reactor Vessel Structural Integrity." The number of EFPYs at the

end of the period of initial operation (40 years) is assumed to be 32, using an assumed 80-percent

capacity factor. Similarly, 48 EFPYs are assumed at the end of the period of extended operation

(60 years), using an assumed 80-percent capacity factor.

RG 1.99, Revision 2, provides two methods (or positions) for determining Charpy USE. Following

Position 1, the percent drop in Charpy USE for a stated copper content and neutron fluence is

determined by reference to Figure 2 of RG 1.99. This percentage drop is applied to the initial

Charpy USE to obtain the adjusted Charpy USE. For Position 2, the percent drop in Charpy USE is

determined by plotting the available data on Figure 2 and fitting the data with a line drawn parallel to

the existing lines that represent the upper bounds of all the plotted points.

Table A-2 of Westinghouse Commercial Atomic Power (WCAP)-15879, Revision 0, "Evaluation of

Pressurized Thermal Shock for D.C. Cook Unit 1 for 40 Years and 60 Years," reports the 48 EFPY

Charpy USE values for the reactor vessel beltline materials for Unit 1; Table A-2 of WCAP-1 3517,

Revision 1, "Evaluation of Pressurized Thermal Shock for D.C. Cook Unit 2," reports the values for

Unit 2. Using the methodology presented in Position 1, the applicant calculated the CNP USE

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values. The 48 EFPY fluence at one fourth of the way through the vessel wall (T/4) is based on a

peak clad base metal fluence of 2.831 x1 019 n/cm2 and 2.457x1 019 n/cm2 for Units 1 and 2,

respectively. The fluence at the T/4 location for Units 1 and 2 was calculated in accordance with RG

1.99, Equation 3.

Fluence values at 48 EFPYs were obtained using the method described in Section 6 of WCAP12483, Revision 1, "Analysis of Capsule U from the American Electric Power Company D.C. Cook

Unit 1 Reactor Vessel Radiation Surveillance Program," for Unit 1 and WCAP-13515, Revision 1,

"Analysis of Capsule U from Indiana Michigan 'Power Company D.C. Cook Unit 2, Reactor Vessel

Radiation Surveillance Program," for Unit 2. The projected 48 EFPY exposure for Unit 1 includes

the plant- and fuel cycle-specific calculated fluence at the end of cycle 16, a projection to the end of

cycle 17, and future projections to 32 EFPYs and 48 EFPYs. The projection to cycle 17 was based'

on the cycle 17 design power distribution, continued operation at a core power level of 3250

megawatts-thermal (MWt), and a design cycle length of 1.45 EFPYs. Projection beyond cycle 17

was based on the assumption of low leakage fuel management and a representative power

distribution bumup averaged over cycles 15 through 17. The analysis conservatively assumed that,

for cycles 18 ahd beyond, the core power level would be uprated to 3600 MWt. In addition, the

analysis applied positive 'a bias of 10 percent to the neutron source in all fuel assemblies located on

the core periphery.

The projected 48 EFPY fluence exposure for Unit 2 includes the plant-specific and fuel cyclespecific calculated fluence at the end of cycle 11, a projection to the end of cycle 12, and projections

to 32 EFPYs and 48 EFPYs. The projection to cycle 12 was based on the cycle 12 design power

distribution, continued operation at a core power level of 3411 MWt, and a design cycle length of 1.4

EFPYs. Projections beyond cycle 12 were based on assumptions of low-leakage fuel management

and that a representative power distribution bumup averaged over cycles 10 through 12 would be

typical of future operating cycles. The analysis conservatively assumed that, for cycles 13 and

beyond, the core power level would be uprated to 3800 MWt. In addition, the analysis applied a

positive bias of 10 percent to the neutron source in all fuel assemblies located on the core periphery;

The NRC recently reviewed the fluence methodology in WCAP-12483 and WCAP-13515, Revision

1, and concluded that the methodology uses approximations, geometrical description, and cross

sections in accordance with the guidance in RG 1.190, "Calculational 'and Dosimetry Methods for

Determining Pressure Vessel Neutron Fluence," issued March 2001. In projecting the fluence

values, Indiana Michigan Power Company (I&M) incorporated a power level that would bound

anticipated future power uprates. The fluence calculation methods described in WCAP-1 2483 and

WCAP-1 3515 are concordant.

As shown in Table 4.2-1 and Table 4.2-2 of the LRA,' the Charpy USE is maintained above 68 J (50

ft-lb) for all base metal (plates and forgings) and welds at 48 EFPYs for both units. The applicant

shows an end of extended operation limiting beltline material Charpy USE of 57 ft-lb for the

intermediate/lower shell circumferential weld of Unit 1 and 66 ft-lb for the intermediate shell plate of

Unit 2. According to regulations, an equivalent margins analysis is not required for either Unit 1 or

Unit 2. Therefore, the applicant has evaluated USE in accordance with 10 CFR 54.21 (c)(1)(ii) and

projected the analyses to the end of the period of extended operation:

A comparison of copper content and initial unirradiated Charpy USE values for the Units 1 and 2

beltline materials listed in Tables 4.2-1 and 4.2-2 of the LRA to the values reported in the NRC

reactor vessel integrity database (RVID2) indicates slight differences for selected plate and weld

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-. I

materials. These slight differences are not significant and do not alter the conclusion that Charpy

USE is maintained above 68 J (50 ft-lb) for all base metal (plates and forgings) and welds at 48

EFPYs for both units. Table 4.2-1 of the LRA does not list the nozzle shell material for Unit 1 as it is

not considered to be a limiting material in accordance with the beltline definition provided in

10 CFR 50.61 (a)(3).

4.2.1.2 Staff Evaluation

The applicant summarized the Charpy USE analyses for the CNP RPV beltline materials in Tables

4.2-1 and 4.2-2 of the LRA. Since all reported end of extended operation Charpy USE values are

above the 68 J (50 ft-lb) screening criterion, the staff finds that, with respect to Charpy USE, the

CNP RPVs have sufficient margin to perform their intended function through the period of extended

operation.

The applicant's end of extended license Charpy USE values are based on the fluence and material

information in a series of WCAP reports submitted as attachments in support of the current P-T

limits at 32 EFPYs, which the NRC approved in its safety evaluation (SE) dated July .18, 2003, for

Unit 1 and the NRC SE dated March 20, 2003, for Unit 2. The WCAP reports for Unit 1 include

WCAP-1 2483, Revision 1, for the fluence calculational methodology and results; WCAP-1 5878,

Revision 0, "D.C. Cook Unit 1 Heatup and Cooldown Limit Curves for Normal Operation for 40

Years and 60 Years," for P-T limits; and WCAP-1 5879, Revision 0, for PTS calculations. The

corresponding reports for Unit 2 include WCAP-1 3515, Revision 1; WCAP-1 5047, Revision 2, "D.C.

Cook Unit 2 WOG Reactor Vessel 60-Year Evaluation Minigroup Heatup and Cooldown Limit

Curves for Normal Operation;" and WCAP-1 3517, Revision 1. Although these WCAP reports

contain fluence and material property information for both 32 EFPYs and 48 EFPYs, the approved

P-T limits for both units are for 32 EFPYs.

The staff confirmed that the Charpy USE-related information in the LRA is consistent with the

WCAP reports and the relevant NRC SEs. The fluence calculational methodology, which used

approximations, geometrical descriptions, and cross sections in accordance with RG 1.190, is

acceptable to the staff, as stated in the two SEs referenced above. Because all of the end of

extended license Charpy USE values are above the 68 J (50 ft-lb) screening criterion, the staff finds

that, with respect to Charpy USE, the CNP RPVs have sufficient margin to perform the intended

function through the period of extended operation.

RAI 4.2.1-1

For additional assurance, the staff performed an independent calculation of the end of extended

license Charpy USE values for the limiting beltline plate and weld of the CNP reactor pressure

vessels (RPVs) and confirmed that the applicant's end of extended license Charpy USE values for

the limiting beltline plate and weld are above the 68 J (50 ft-lb) screening criterion and, except for

the three welds of Unit 2,- are in reasonable agreement with the staff's calculated values. For

example, the end of extended operation limiting beltline material Charpy USE values calculated by

the staff is 58 ft-lb for Unit 1 and 65 ft-lb for Unit 2 , close to the applicant's values of 57 and 66 ft-lb

respectively. To clarify the discrepancy with the three welds of Unit 2, the staff issued RAI 4.2.1-1.

By letter dated June 16, 2004, the applicant responded to the RAI by stating that it based all end of

extended license USE values for Unit 1 beltline plates and welds and Unit 2 plates on RG 1.99,

Revision 2, Position 1.2. Consequently, the applicant, in its letter dated August 11, 2004, indicated

that it based the end of extended license USE values for Unit 2 beltline welds on RG 1.99, Revision

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2, Position 2.2. The staff verified that, when the analysis uses surveillance data (Position 2.2), the

staff's end of extended license USEs for the three welds of Unit 2 correspond to those in LRA

Section 4.2.1. The staff also reviewed the Charpy USE values at 32 EFPYs for all beltline and

nozzle materials, including nozzle shell plates and welds, which are not reported in the LRA, to

ensure that the limiting plate and weld at 32 EFPYs remain limiting at the end of the extended

license period. Since the applicant's RPV Material Surveillance Program includes some beltlinematerials (refer to Aging Management Program (AMP) B.1.26 in Section 3.0.3.2.10 of this SER for a

description of the Reactor Vessel Integrity Program), the staff applied Position 2.2 in RG 1.99,

Revision 2, in estimating the percentage drop in end of extended license Charpy USE for these

beltline materials. The staff confirmed that, although the percentage drop in end of extended

license Charpy USE is greater using Position 2.2 in the RG for the two beltline plates of Unit 1

having surveillance data, the change is not large enough to make either one limiting. Therefore, all

RPV beltline shell and nozzle materials will continue to satisfy the Charpy USE value requirementsof Appendix G to 10 CFR Part 50, through the period of extended operation for the CNP units.

Thus, the staff concludes that the applicant's TLAA for calculating the end of extended license

Charpy USE values of the CNP RPV beltline materials is acceptable because it meets the

requirements of 10 CFR 54.21 (c)(1 )(ii) and will ensure that the RPV materials will have adequate

Charpy USE values and fracture toughness through the period of extended operation.

4.2.2 Pressurized Thermal Shock

Fracture toughness requirements to protect the RPVs of PWRs against possible consequences of

PTS are founded in 10 CFR 50.61. Licensees must perform an assessment of the RPV materials'

projected values of the reference temperature (RT) for PTS (RTPTs) through the end of their

operating licenses. The regulation requires each licensee to calculate the end-of-license RThrs

value for each material located within the beltline of the RPV. The RTPTs value for each beitline

material is the sum of the unirradiated reference nil-ductility transition temperature (unirradiated

RTNDT), the shift in the RTNDT value caused by neutron irradiation of the material (ARTNDT), and a

margin value to account for uncertainties (M). The regulation provides screening criteria against

which the calculated values are evaluated.

Pursuant to 10 CFR 50.61 (b)(2), RPV beitline base metal materials (forging or plate materials) and

longitudinal (axial) weld materials have adequate protection against PTS events if the calculated

RTpTs values are less than or equal to 132 OC (270 .F). The RPV beltline circumferential weld

materials are considered to have adequate protection against PTS events if the calculated RTpTS

values are less than or equal to 148 0C (300 OF). In this RG, ARTNDT is the product of a chemistryfactor and a fluence factor, where the fluence factor is dependent on the neutron fluence at the cladto-base metal interface, and the chemistry factor is dependent on information from either the

surveillance material or from the tables in the RG. 10 CFR 50.61(c) provides two methods for -

determining RTpTs, one for material that does not have surveillance data available and one for

material that has surveillance data. RG 1.99, Revision 2, Sections 1.1 and 2.1, respectively

describe the two methods. If the RPV beltline material is not represented by surveillance data, its

chemistry factor may be determined using the tables'and the methodology documented in Position

1.1 in the RG. A chemistry factor determined from the tables in the RG will vary according to the

amount of copper and nickel in the material. If the RPV beltline material is represented by

surveillance data, its chemistry factor may be determined from the surveillance data using the

methodology documented in Position 2.1 of the RG. The methods of determining RTPTS values in

10 CFR 50.61 are equivalent to the methods of determining RTNDT values in RG 1.99, Revision 2.

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4.2.2.1 Summary of Technical Information in the Application

Section 4.2.2 of the LRA addressed the requirement that RPV beltline materials have RTPTS values

not exceeding the screening criteria of 10 CFR 50.61 for the licensed period of operation of the

vessel. The applicant stated that the RTpTs values have been calculated for all beltline materials

through the period of extended operation using Position 1.1 and Position 2.1 in RG 1.99, Revision 2,

as reported in LRA Section 4.2.2. A value of 48 EFPY was used as the end of extended license

criterion for the RPVs. Table 4.2-3, "Evaluation of Reactor Vessel (48 EFPY) PTS - Unit 1," and

Table 4.2-4, "Evaluation of Reactor Vessel (48 EFPY) PTS - Unit 2," of the LRA contain RTpTs

information for all beltline materials. This information includes the weight percent of copper and

nickel in the steel, the end of extended operation fluence for the RPV clad-to-base metal interface,

the initial RTNDT, and the calculated RTp. values at the end of the extended operation.

Specifically, the end of extended operation limiting beltline material RTpTs is reported to be 139 'C

(283 "F) for the intermediate/lower shell circumferential weld of Unit 1 and 108 "C (227 "F) for the

intermediate shell plate of Unit 2. The applicant concluded that the end of extended license RTpTS

results are below the screening criteria of 132 "C (270 OF) for plates and axial welds and 148 IC

(300 IF) for circumferential welds. The applicant stated that it has projected the calculations through

the period of extended operation and has met the requirements of 10 CFR 54.21 (c)(1)(ii).

4.2.2.2 Staff Evaluation

The applicant summarized the end of extended operation RTpTs results for the CNP RPV beltline

materials in Tables 4.2-3 and 4.2-4 of the LRA. Because the end of extended operation RTPTs

values are below the screening criteria of 10 CFR 50.61, the staff finds that, with respect to RTpTs,

the applicant's RPVs have sufficient margin to perform their intended function through the period of

extended operation.

The applicant based end of extended operation RTp-s values on the fluence and material

information found in the same series of WCAP reports submitted as attachments to support the

current P-T limits at 32 EFPYs for Unit 1 and the P-T limits at 32 EFPYs for Unit 2 which are

discussed in Section 4.2.1.2 of this SER. The staff confirmed that the RTp.-related information in

the LRA, including the fluence calculational methodology and results, is consistent with that in the

WCAP reports and in the NRC SEs referenced in Section 4.2.1.2 of this SER. The staff performed

an independent calculation of the end of extended operation RTpTs values for the limiting beltline

plate and weld of the CNP RPVs and confirmed that the applicant's end of extended operation

RTpTs values and the staff's calculated values for the limiting beltline plate and weld are identical and

below the screening criteria. The staff also reviewed the RTpTs values at 32 EFPYs for all beltline

and nozzle materials, including nozzle shell plates and welds, which are not reported in the LRA, to

ensure that the limiting plate and weld at 32 EFPYs remain limited at the end of extended license.

For the beltline materials having surveillance data, the staff applied Position 2.2 in RG 1.99,

Revision 2, as well as Position 1.2, in estimating its end of extended license RTpTs values and

confirmed that the surveillance data predicted less embrittlement. Based on the above discussion,

the staff concludes that all RPV beltline shell and nozzle materials will continue to satisfy the RTpTs

value requirements of 10 CFR 50.61 through the period of extended operation for the CNP units.

The applicant's TLAA for calculating the end of extended license RTPTS values of the CNP RPV

beltline materials is acceptable because it meets the requirements of 10 CFR 54.21 (c)(1)(ii) and will

ensure that the RPV materials will have adequate RTPTs values and fracture toughness through the

period of extended operation for the CNP units.

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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 (RCPB) in nuclear power plants. The applicant established the

P-T limits by calculations that use the materials and fluence data obtained through the unit-specific

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 limit 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 Xl of the ASME Code.

The critical locations in the RV beltline region for calculating heatup and cooldown P-T curves are

the 1/4T and 3/4T locations, which correspond to the maximum depth of the postulated inside

surface and outside surface defects, respectively.

4.2.3.1 Summary of Technical Information in the Application

Appendix G to 10 CFR Part 50 requires operation of the RPV within established P-T limits.

Analyses based on data obtained through the unit-specific Reactor Surveillance Capsule Program

establish these limits.

I&M submitted license amendment requests for the Unit 1 and 2 RCS P-T curves. The revised Unit

1 P-T curves, which the NRC approved by means of License Amendment Number 278, specify

limits on RCS pressure and temperature for up to 32 EFPYs. For cycle 18 and beyond, the curves

are based on an assumed core power level of 3600 MWt. The revised Unit 2 P-T curves, which the

NRC approved by means of License Amendment Number 255, specify limits on RCS pressure and

temperature for up to 32 EFPYs, based on an assumed core power level of 3800 MWt. The revised

P-T curves are based on fluence analysis that complies with RG 1.190 and uses ASME Code Case

N-641. The bases for the Units 1 and 2 EFPY P-T limits are documented in WCAP-15878, Revision

0, and WCAP-1 5047, Revision 2, respectively. In addition, Section 9.0, Figures 9-3 and 9-4, of

each respective WCAP, report the 48-EFPY P-T results. The operating window at 48 EFPYs is

sufficient to conduct normal heatup and cooldown operations for both Units 1 and 2. Therefore, the

applicant has projected approved P-T limits for Units 1 and 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

Similar to the end of extended license Charpy USE and RTpTs values discussed in Sections 4.2.1.2

and 4.2.2.2 of this SER, the applicant based its end of extended license P-T limits on the fluence

and material information in the WCAP reports submitted as attachments to support the current P-T

limits at 32 EFPYs for Units 1 and 2. The staff confirmed that the information related to P-T limits in

the LRA, including the fluence calculational methodology and results, is consistent with that in the

WCAP reports and in the NRC SEs approving the current P-T limits for CNP units. Thus, the

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applicant's TLAA for calculating the end of extended license P-T limits of the CNP RPV beltline

materials is acceptable because it meets the requirements of 10 CFR 54.21 (c)(1)(ii) and will ensure

that the operating window at 48 EFPYs is sufficient to conduct normal heatup and cooldown

operations through the period of extended operation for the CNP units. However, accepting the

applicant's TLAA regarding P-T limits for 48 EFPYs does not mean that the CNP licensing basis

may now include these limits. The NRC will process any P-T limit change for CNP, Units 1 and 2,

as separate license amendments; which could modify the facility's technical specifications.

4.2.4 UFSAR Supplement

On the basis of the staffs evaluation described above, the summary description for the RCS TLAA

for RPV Charpy USE, PTS, and P-T limits described in the UFSAR Supplement (Appendix A to the

LRA) adequately describes this TLAA, as required by 10 CFR 54.21.

4.2.5 Conclusion

The staff reviewed TLAAs regarding the maintenance of acceptable Charpy USE values and P-T

limits for the CNP RPV materials and the ability of the CNP RPV to resist failure during postulated

PTS events. Based on this evaluation, the staff concludes that the applicant's TLAAs for Charpy

USE, PTS, and P-T limits meet the respective requirements of Appendix G to 10 CFR Part 50, as

well as 10 CFR 50.61 for the CNP RPV beltline materials to the end of extended license. Therefore,

they satisfy the requirements of 10 CFR 54.21 (c)(1 )(ii) to the end of the period of extended

operation. However, the NRC must process any P-T limit changes for CNP, Units 1 and 2, as

separate license amendments, thereby, modifying the facility's technical specifications.

4.3 Metal Fatigue

A metal component subjected to cyclic loading at loads less than the static design load may fail due

to fatigue. Metal fatigue of components may have been evaluated based on an assumed number of

transients or cycles for the current operating term. The validity of such metal fatigue analysis is

reviewed for the period of extended operation.

4.3.1 Summary of Technical Information in the Application

The applicant discussed the design of CNP RCPB components in Section 4.3.1 of the LRA. The

pressurizer, reactor vessel, control rod drive mechanism (CRDM) housings and steam generators

were designed to the ASME Boiler and Pressure Vessel Code, Section III requirements for Class 1

components. The reactor vessel intemals were evaluated using the ASME Code Class 1 fatigue

criteria. Table 4.3-1 of the LRA lists the transients and number of transient cycles used in the

design of ASME Class 1 components. Table 4.3-1 also lists the estimated number of transient

cycles for 60 years of plant operation for each unit. The applicant estimated that the number of

design cycles will remain bounding for the period of extended operation. Therefore, the applicant

indicated that the fatigue analyses will remain valid in accordance with the requirements of

10 CFR 54.21 (c)(1)(i).

The applicant indicated that the Fatigue Monitoring Program (FMP) tracks the RCS design

transients. The FMP is described in Appendix B of the LRA.

4-10
The applicant indicated that RCPB (Class 1) piping was designed to United States of America

Standard (USAS) B31.1. This standard does not require an explicit fatigue analysis of piping

components. However, USAS B31.1 does require a reduction in the allowable bending stress range

if the number of full range bending stress cycles exceed 7,000. The applicant indicated that, based

on its review of the Class 1 piping systems, the existing analyses remain valid for the period of

extended operation in accordance with the requirements of 10 CFR 54.21 (c)(1)(i).

In addition to the design of ASME Code Class 1 components using transient cycles listed in Table

4.3-1 of the LRA, the applicant identified evaluations performed to address other specific issues.

These evaluations were performed for the surge line to address NRC Bulletin 88-11, Pressurizer

Surge Line Thermal Stratification," and the normal and alternate charging lines and the auxiliary

pressurizer spray line to address NRC Bulletin 88-08, "Thermal Stresses in Piping Connected to

Reactor Coolant Systems." The applicant indicated that the fatigue analyses of these lines remain

valid for the period of extended operation in accordance with the requirements of

10 CFR 54.21 (c)(1)(i).

The applicant discussed the evaluation of non-Class 1 components in Section 4.3.2 of the LRA.

The applicant indicated that the equipment specifications for several heat exchangers required that

the supplier verify that ASME Code Section 1II, paragraph N-415.1 was satisfied for the design

transients. As discussed above, the applicant estimated that the number of design cycles will

remain bounding for the period of extended operation. Therefore, the fatigue analyses remain valid

in accordance with the requirements of 10 CFR 54.21 (c)(1)(i).

The applicant indicated that non-Class 1 piping was designed to USAS B31.1. Therefore, the piping

components require that a stress reduction factor be applied to the allowable thermal bending stress

range if the number of full range cycles exceeds 7,000. The applicant indicated that most piping

systems within the scope of license renewal are bounded by the 7,000 cycles. Therefore, the

applicant concluded that the existing pipe stress calculations are valid for the period of extended

operation in accordance with 10 CFR 54.21 (c)(1)(i).

The applicant discussed the evaluation of environmentally assisted fatigue of RCPB components in

Section 4.3.3 of the LRA. The applicant provided the results of an evaluation of the environmental

effects on the components listed in NUREG/CR-6260, "Application of NUREG/CR-5999 Interim

Fatigue Curves to Selected Nuclear Power Plant Components." The applicant indicated that it used

the environmental fatigue correlations in NUREG/CR-6583, "Effects of LWR Coolant Environments

on Fatigue Design Curves of Carbon and Low-Alloy Steels," and NUREG/CR-5704, "Effects of LWR

Coolant Environments on Fatigue on Fatigue Design Curves of Austenitic Stainless Steels," in the

evaluations. The applicant's evaluation indicated that the environmental fatigue usage factor for the

surge line may exceed 1.0 during the period of extended operation. The applicant committed to

further actions to address the surge line prior to the period of extended operation.

4.3.2 Staff Evaluation

As discussed in the previous section, components of the CNP RCPB were designed to the Class 1

requirements of the ASME Code. These requirements contain explicit criteria for the fatigue

analysis of components. Consequently, the applicant identified the fatigue analysis of these

components as TLAAs. The staff reviewed the applicant's evaluation of the RCPB components for

compliance with the provisions of 10 CFR 54.21 (c)(1).

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L

The specific design criterion for fatigue analysis of RCPB components involves calculating the

cumulative usage factor (CUF). The fatigue damage in the component caused by each thermal or

pressure transient depends on the magnitude of the stresses caused by the transient. The CUF

sums the fatigue damage resulting from each transient. The design criterion requires that the CUF

not exceed 1.0. The applicant projected that the number of design cycles assumed for each

transient will not be exceeded during the period of extended operation. Table 4.3-1 of the LRA

provides the current cycle counts and estimated cycle counts at 60 years of plant operation for

transients used in the design of ASME Code Class 1 components. The transients listed in Table

4.3-1 of the LRA include the design transients specified in UFSAR Table 4.1 -10, except for the

primary to secondary leak tests specified for the Unit 1 Model 51 R replacement steam generators.

The applicant indicated that it no longer performed this leak test and, therefore, did not listed it in

Table 4.3-1.

Table 4.3-1 indicated that unit loading and unloading transients at 5 percent of full power per minute

are not monitored. The applicant indicated that the number of these design transients is

conservative because CNP units are base loaded plants. The staff agrees that the number of

design cycles listed for these transients is conservative based on the information presented in

NUREG/CR-6260 on older vintage Westinghouse plants. The applicant also indicated that

secondary side hot standby feedwater cycling is not monitored due to modified plant design and

operating procedures to preclude feedwater nozzle cracking. These modifications were described in

a November 26, 1979, I&M letter to the NRC. The remaining transients are tracked by the

applicant's FMP. The staff finds that the applicant's FMP tracks the significant design transients

listed in Table 4.3-1.

The Westinghouse Owners Group (WOG) issued Topical Report WCAP-1 4577, Revision 1 -A,

"Aging Management for Reactor Intemals," to address the aging management of the RVI. Section

2.3.1 of the LRA indicates that WCAP-1 4577; Revision 1-A was reviewed as a source of input

information for CNP. The staff's review of WCAP-1 4577, Revision 1-A identified a number of issues

that should be addressed on a plant specific basis. Renewal Applicant Action Item 11 specified in

WCAP-14577, Revision 1-A indicates that the fatigue TLAA of the RVI should be addressed on a

plant specific basis. Section 4.3 of the LRA indicates that the action item was addressed in Section

4.3.1 of the LRA. In Section 4.3.1, the applicant indicated that the number of design transients will

not be exceeded during the period of extended operation. Additionally, the applicant's FMP will

track the number of design transient cycles during the period of extended operation. The staff finds

that the applicant has adequately addressed Renewal Applicant Action Item 11 specified in WCAP1577, Revision 1 -A by assuring that the design transients that are significant contributors to design

fatigue usage of the RVI components will be monitored by the FMP.

The WOG issued WCAP-1 4575-A, "Aging Management Evaluation for Class 1 Piping and

Associated Pressure Boundary Components," to address aging management of the RCS piping.

Section 2.3.1 of the LRA indicates that WCAP-14575-A, 1-A was reviewed as a source of input

information for CNP. Tables 3-2 through 3-16 of WCAP-1 4575-A list RCS components for which

fatigue could be significant. The staff review of WCAP-14575-A identified a number of issues that

should be addressed on a plant specific basis. Renewal Applicant Action Item 8 indicates that the

applicant should address components labeled l-M and E-RA in Tables 3-2 through 3-16 of WCAP14575-A. As discussed previously, the design of RCPB piping conforms to the requirements of

USAS B31.1. The standard does not require an explicit fatigue analysis. Instead, USAS B31.1

requires that a stress reduction factor be applied to the allowable thermal bending stress range if the

number of full range cycles exceeds 7,000. The applicant indicated that the number of full range

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bending stress cycles will not exceed 7,000 during the period of extended operation for the RCPB

piping. The staff finds that the applicant's actions adequately address Renewal Applicant Action

Item 8. The applicant did perform fatigue analyses of some RCPB piping in response to NRC

Bulletins 88-08 and 88-11.

The WOG has issued the generic WCAP-14574-A to address aging management of pressurizers.

Section 2.3.1 of the LRA indicates that WCAP-1 4574-A was reviewed as a source of input

information for CNP. The staff's review of WCAP-14574-A identified a number of issues that should

be addressed on a plant specific basis. Renewal Applicant Action Item 1 requests the applicant to

demonstrate that the pressurizer sub-component CUFs remain below 1.0 for the period of extended

operation. Table 2-10 of WCAP-14574-A indicates that the ASME Code, Section III, Class 1 fatigue

CUF criterion could be exceeded at several pressurizer sub-component locations during the period

of extended operation. WCAP-14574-A also identifies recent unanticipated transients not

considered in the original ASME Code, Section III, Class 1 fatigue analyses, including inflow/outflow

thermal transients.

The applicant indicated that it had modified CNP operating procedures to decrease the severity of

transients resulting from pressurizer surges during heatup and cooldown. The applicant stated that

its reevaluation of the usage factors of the limiting pressurizer items in the lower head had shown,

them to be less than 1.0. The applicant also indicated that the evaluation was updated for 60 years

and the usage factors still remain below 1.0. The staff finds that the applicant's reevaluation has

adequately addressed the renewal applicant action item related to its concern about the pressurizer

sub-component fatigue usage for the period of extended operation, including inflow/outflow thermal

transients.

Renewal Applicant Action Item 1 also requested that the applicant discuss the impact of the

environmental fatigue correlations provided in NUREG/CR-6583, "Effects of LWR Coolant

Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels," and NUREG/ CR-5704

on the above results. The applicant did not discuss this issue in the LRA. The applicant has not

provided the CUFs for the sub-components listed in Table 2-10 of WCAP-1 4574-A or discussed the

impact of the environmental fatigue correlations on these sub-components. As discussed

previously, the applicant's evaluation of the surge line indicated that the environmental fatigue usage

factor may exceed 1.0 during the period of extended operation. The staff concludes that a

possibility exists that the components listed in Table 2-10 of WCAP-1 4574-A could also exceed the

fatigue usage limit during the period of extended operation when environmental fatigue effects are

considered.

The staff review of previous license renewal applications for Westinghouse facilities found that the

pressurizer surge line nozzle is the most limiting fatigue location for the pressurizer subcomponents. The staff concludes that the pressurizer surge line nozzle is an acceptable sample

component location for assessing the impact of environmental fatigue on the CNP pressurizer

components. The applicant committed to conduct further actions to address environmental fatigue

of the surge line piping prior to the period of extended operation. This part of Commitment #31 in

Appendix A of this SER. If the applicant's evaluation of the surge line nozzle for environmental

effects indicates that additional actions are required to manage its fatigue usage during the period of

extended operation, then the applicant should evaluate the remaining pressurizer components for

the effects of environmental fatigue as part of its corrective action.

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RAI 4.3. 1-1

The applicant discussed the fatigue evaluation of the Unit 1 auxiliary spray line that was performed

in response to NRC Bulletin 88-08. The applicant indicated that this fatigue evaluation is contained

in WCAP-14070, "Evaluation of Donald C. Cook Units 1 and 2 Auxiliary Spray Piping per NRC

Bulletin 88-08," dated July 1994. The applicant stated that the basis of the transient definitions used

in the analysis is the number of design heatup and cooldown transients and that the number of

design transients was found acceptable for 60 years of plant operation. Therefore, the applicant

concluded that the fatigue analysis results presented in WCAP-14070 remain valid for the period of

extended operation. In RAI 4.3.1-1, the staff requested that the applicant provide a copy of WCAP14070.

The applicant's June 16, 2004, response provided proprietary and non-proprietary versions of

WCAP-14070. The staff's review of WCAP-1 4070 confirmed the applicant's statement that the

transient definitions are based on the number of design heatup and cooldown cycles. The staff

review also found that some of the cyclic loading conditions for the leaking auxiliary spray isolation

valve appear to be time dependent. Therefore, the staff could not confirm the applicant's conclusion

that the analysis remains valid for the period of extended operation. The applicant's October 18,

2004, response confirmed that some of the cycles assumed in the fatigue analysis are valid for only

40 years of plant operation. The applicant committed to perform one or more of the following four

actions for the auxiliary spray line piping evaluated in WCAP-14070:

(1) perform a plant specific fatigue analysis of the auxiliary spray line piping prior to the period of

extended operation to ensure that the CUFs remain less than 1.0

(2) repair the piping at the affected locations

(3) replace the piping at the affected locations

(4) manage the effects of fatigue of the auxiliary spray line piping by an NRC-approved

inspection program at inspection intervals to be determined by a method acceptable to the

NRC staff.

This is Commitment #40 in Appendix A of this SER. The staff notes that, if the fourth option is

selected, the applicant must provide inspection details, including scope, qualification, method, and

frequency to the NRC for review and approval prior to the period of extended operation. An AMP

under the fourth option would be a departure from the design basis CUF evaluation, described in the

UFSAR Supplements and, therefore, would require a license amendment pursuant to

10 CFR 50.59. In view of the above, the staff finds the applicant's proposed actions to be an

acceptable approach to address fatigue of the auxiliary spray line piping during the period of

extended operation in accordance with 10 CFR 54.21 (c)(1).

RAI 4.3.2-1

The applicant discussed the evaluation of non-Class 1 components in Section 4.3.2 of the LRA. As

discussed previously, USAS B31.1 requires a reduction in the allowable bending stress range if the

number of full range bending stress cycles exceed 7,000. The applicant indicated that only the RCS

sampling system piping could exceed 7,000 thermal cycles during the period of extended operation.

The applicant further indicated that it had prepared a calculation to justify operation of the RCS

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sampling system piping for 99,000.cycles. The applicant then concluded that the RCS sampling

system piping analysis is not a TLAA. In RAI 4.3.2-1, the staff requested that the applicant clarify

whether it had prepared the RCS sampling system piping calculation to support the CNP LRA. The

staff indicated that, if the applicant had prepared this calculation to support the LRA, then the

sampling system piping analysis should be considered a TLAA that has been projected to the end of

the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(ii).

The applicant's June 16, 2004, response indicated that the sampling piping calculation had been

revised in response to a condition report that indicated that the 7,000 cycle could be exceeded

during the current 40-year license term. The applicant reasoned that it had used a conservative

number of cycles in the revised analysis and, therefore, the calculation was not based on an explicit

time limit defined by the current operating term. The staff agrees that the number of cycles used by

the applicant in the revised analysis is conservative for the period of extended operation. However,

the staff still considers the applicant's pipe stress analysis a TLAA that was demonstrated to remain

valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

The applicant indicated that the FMP will continue during the period of extended operation and will

assure that design cycle limits are not exceeded. The applicant's FMP tracks transients and cycles

of RCS components that have explicit design transient cycles to assure that these components

remain within their design basis. 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-166.was resolved for the current 40-year design life

of operating components, the staff identified GSI-1 90, "Fatigue Evaluation of Metal Components for

60-year Plant Life," to address license renewal. The NRC closed GSI-1 90 in December 1999, by

concluding the following:

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-1 90 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

leaks 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.

RAI 4.3.3-1

Section 4.3.3 of the LRA discussed the applicant's evaluation of the impact of the reactor water

environment on the fatigue life of components. The discussion referenced the fatigue sensitive

component locations for an early vintage Westinghouse plant identified in NUREG/CR-6260.- The

applicant indicated that it had used the design usage factors provided in Table 5-98 of NUREG/CR6260 for the evaluation of the charging nozzle, safety injection nozzle and RHR tee. -The design

usage factors reported in NUREG/CR-6260 were based on an evaluation of the Turkey Point facility,

including a plant specific evaluation of the RHR piping and detailed finite element analyses of the

charging and safety injection nozzles. In RAI 4.3.3-1, the staff requested that the applicant discuss

4-15
I

the applicability of these analyses to the CNP. The staff requested that the discussion also compare

piping sizes and thicknesses, including the design of the thermal sleeves between CNP and Turkey

Point. The staff further requested that the discussion also include a comparison of the number and

type of design transients cycles between CNP and Turkey Point.

The applicant's June 16, 2004 response indicated that the Class 1 RHR piping at the four-loop CNP

units has a different configuration than the RHR piping at the three-loop Turkey Point units.

Therefore, the applicant committed to undertake one or more of the following five actions for the

RHR piping prior to the period of extended operation:

(1) perform a plant specific fatigue analysis, including environmental effects, to demonstrate that

the CUF remain less than 1.0

(2) repair the Class 1 portions of RHR at the affected locations

(3) replace the Class 1 portions of RHR at the affected locations

(4) manage the effects of fatigue of the Class 1 portions of RHR piping by an NRC-approved

inspection program at inspection intervals to be determined by a method acceptable to the

NRC staff

(5) monitor ASME Code activities to use the environmental fatigue methodology approved by

the ASME Code committee and the NRC

This is Commitment #35 in Appendix A of this SER. The fifth option is n6t an alternative option to

resolve the environmental fatigue issue. The first and fourth options include the use of an

environmental fatigue methodology approved by the NRC. The staff notes that, if the fourth option

is selected, the applicant must provide the inspection details, including scope, qualification, method,

and frequency to the to the NRC for review and approval prior to the period of extended operation.

An AMP under the fourth option would be a departure from the design basis CUF evaluation,

described in the UFSAR Supplements and, therefore, would likely require a license amendment

pursuant to 10 CFR 50.59. On the basis of the above discussion, the staff finds the applicant's

proposed program to be an acceptable plant-specific approach to address environmentally assisted

fatigue of the RHR line during the period of extended operation in accordance with

10 CFR 54.21(c)(1).

The applicant's June 16, 2004, response indicated that the CNP charging and safety injection

nozzles are similar to the ones evaluated in NUREG/CR-6260. The applicant referenced the RCS

nozzle configurations shown in Figures 2-11 and 2-12 of WCAP-1 4575-A to support this position.

The staff review of WCAP-1 4575-A found that the CNP nozzles are identified as second generation

nozzle designs. Figures 2-11 and 2-12 show that these nozzles have a counterbore near the

thermal sleeve attachment weld. The NUREG/CR-6260 finite element models of charging and

safety injection nozzles do not show this counterbore. Therefore, the CNP nozzles are slightly

different from the ones evaluated in NUREG/CR-6260. In addition, the applicant indicated that two

of the safety injection nozzles do not contain thermal sleeves. The finite element models in

NUREG/CR-6260 contain thermal sleeves. Therefore, the staff concludes that the NUREG/CR-6260

finite element models are not directly applicable to the CNP nozzles.

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The applicant's response also indicated that the major design transients for CNP are similar to those

evaluated in NUREG/CR-6260. ,Thie Turkey Point plant evaluated in NUREG/CR-6260 is a threeloop Westinghouse plant, while CNP is a four-loop Westinghouse plant. NUREG/CR-6260 also

evaluates a four-loop Westinghouse plant. Section 5.4.5 of NUREG/CR-6260 indicates that the

highest safety injection nozzle fatigue usage for the four loop Westinghouse plant occurred at the

boron injection tank nozzle which is different from the location evaluated for Turkey Point.

On the basis of the above discussion, it was not clear to the staff whether the design usage factors

for the charging and safety injection nozzles contained in Table 5-98 of NUREG/CR-6260 are

directly applicable to CNP. The staff requested that the applicant provide additional information

regarding this issue. In its September 21, 2004, supplemental response, the applicant committed to

perform one or more of the following five actions for the safety injection and charging nozzles prior

to the period of extended operation:

(1) perform a plant specific fatigue analysis, including environmental effects, to demonstrate that

the CUF remain less than 1.0

(2) repair the Class 1 charging and safety injection nozzles at the affected locations

(3) replace the Class 1 charging and safety injection nozzles at the affected locations

(4) manage the effects of fatigue of the Class 1 charging and safety injection nozzles by an

NRC-approved inspection program at inspection intervals to be determined by a method

acceptable to the NRC staff

(5) monitor ASME Code activities to use the environmental fatigue methodology approved by

the ASME Code committee and the NRC

This is Commitment #33 in Appendix A of this SER. The applicant's proposed actions are the same

as those proposed above for the RHR piping and found acceptable by the staff. As discussed

previously, if the fourth option is selected, the applicant must provide the inspection details, including

scope, qualification, method, and frequency the to the NRC for review and approval prior to the

period of extended operation. An AMP under the fourth option would be a departure from the

design basis CUF evaluation described in the UFSAR Supplements and, therefore, would require a

license amendment pursuant to 10 CFR 50.59. On the basis of the above discussion, the staff finds

the applicant's proposed program to be an acceptable plant-specific apprdach to address

environmentally assisted fatigue of the safety injection and charging nozzles during the period of

extended operation in accordance with 10 CFR 54.21(c)(1).-

4.3.3 UFSAR Supplement

The applicant provided a UFSAR Supplement description of the FMP in Section A.2.1.12 of the LRA

and a description of its TLAA evaluation for Class 1 and non-Class 1 component fatigue analyses in

Section A.2.2.2 of the LRA. The staff requested that the applicant update Section A.2.2.2 to include

the following: (1) a discussion of each of the actions selected to evaluatethe auxiliary spray line.

piping (Commitment #40) and (2) a discussion of each of the actions selected to evaluate the

environmental fatigue of the safety injection nozzles, charging nozzles (Commitment #33) and the

RHR line (Commitment #35). The staff identified this as Confirmatory Item 4.3-1.

4-17
The applicant's January 21, 2005, response provided the updated UFSAR Supplement for Section

A.2.2.2. The updated UFSAR Supplement contains a discussion of the applicant's commitment to

perform additional actions to address fatigue of the auxiliary spray line piping prior to the period of

extended operation and its commitment to perform additional actions to address environmental

fatigue of the pressurizer surge line (Commitment #31), safety injection nozzles, charging nozzles

and the RHR line prior to the period of extended operation. As described in the previous section of

this SER, the staff considered these additional proposed actions and found them acceptable. The

staff concludes that the revised UFSAR Supplement adequately describes the applicant's actions to

address metal fatigue. Therefore, Confirmatory Item 4.3-1 is closed.

4.3.4 Conclusion

The staff has reviewed the applicant's metal fatigue TLAA and concludes that the applicant's actions

and commitments satisfy the requirements of 10 CFR 54.21 (c)(1). The staff has also reviewed the

UFSAR Supplement and finds that the applicant's revised UFSAR Supplement provides a sufficient

description of the metal fatigue TLAA to satisfy the requirements of 10 CFR 54.21 (d).

4.4 Environmental Qualification of Electrical Components

The TLAA for environmental qualification (EQ) of electrical components includes all long-lived,

passive and active, electrical, and instrumentation and controls (I&C) components that are located in

harsh environments. The harsh environments are those areas of the plant that are subjected to the

environmental effects by a loss-of-coolant accident (LOCA) or HELB and that are important to

safety. These components comprise safety related and Q-list equipment, nonsafety related

equipment, the failure of which could prevent satisfactory accomplishment of any safety related

function, and the necessary post-accident monitoring equipment.

Pursuant to 10 CFR 54.21 (c)(1), applicants must provide a list of EQ TLAAs in the LRA and must

demonstrate one of the following three items for each EQ component:

(1) The analyses remain valid for the period of extended operation

(2) The analyses have been projected to the end of the period of extended operation

(3) The effect of aging on the intended functions will be adequately managed for the period of

extended operation.

4.4.1 Summary of Technical Information in the Application

The CNP Environmental Qualification of Electrical Components Program (hereafter referred to as

the Environmental Qualification (EQ) Program) manages component thermal, radiation, and cyclical

aging, as applicable, through the use of aging evaluations based on 10 CFR 50.49(f) qualification

methods. Pursuant to 10 CFR 50.49(f), EQ components not qualified for the applicable term must

be refurbished, replaced, or have their qualification extended before reaching the qualified aging

limits. Aging evaluations for EQ components that specify a qualification of at least 40 years are

considered TLAAs for license renewal. The EQ Program ensures the maintenance of these EQ

components within the bounds of their qualification.

4-18
The EQ Program is an existing CNP program that was established to meet commitments

associated withl 0 CFR 50.49. The CNP EQ Program is consistent with Generic Aging Lessons

Learned (GALL) Report, NUREG-1 801, AMP X.E1,"Environmental Qualification of Electric

Components."

Pursuant to 10 CFR 54.21 (c)(1) the applicant chose option (3) to demonstrate that the EQ Program

activities will adequately manage the effects of aging on the EQ equipment for the period of

extended operation.

4.4.2 Staff Evaluation

For the electrical equipment identified in LRA Section 4.4, the applicant used the criteria of

10 CFR 54.21 (c)(1 )(iii) in its TLAA evaluation to demonstrate that it will adequately manage the

aging effects of EQ equipment during the period of extended operation. The staff reviewed the EQ

Program to determine whether it will assure that the electrical and I&C components covered under

this program will continue to perform their intended functions consistent with the CLB for the period

of extended operation. The staff's evaluation of the components qualification focused on how the

EQ Program manages the aging effects to meet the requirements delineated in 10 CFR 50.49.

The staff reviewed the information provided in the LRA. On the basis of its review, the staff finds

that the EQ Program, which the applicant claimed to be consistent with GALL AMP X.E1, is capable

of programmatically managing the qualified life of components within the scope of the program for

license renewal. The continued implementation of the EQ Program provides reasonable assurance

that the aging effects will be managed and that components within the scope of the EQ program will

continue to perform their intended functions for the period of extended operation.

4.4.3 Conclusion

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 functions of electrical components for the

period of extended operation by using the existing EQ Program as required by

10 CFR 54.21 (c)(1 )(iii). The staff also concluded that the UFSAR Supplement contains a summary

description of the programs and activities for the evaluation of TLAA as required by

10 CFR 54.21 (d).

4.5 Concrete Containment Tendon Prestress

4.5.1 Summary of Technical Information in the Application

The prestressing tendons in prestressed concrete containments lose prestressing forces with time

as the result of creep and shrinkage of concrete, as well as relaxation of the prestressing steel.

During the design phase, engineers estimate these losses to arrive at the predicted prestressing

forces at the end of operating life, normally 40 years. The loss of tendon prestress analysis is a

TLAA only for prestressed concrete containments.

This topic does not apply to ice condenser containments. The reinforced concrete containments at

CNP do not use prestressed tendons.

4-19
4.6 Containment Liner Plate and Penetration Fatigue Analyses

The interior surface of a concrete containment structure is lined with thin metallic plates to provide a

leak-tight barrier against the uncontrolled release of radioactivity to the environment, as required by

10 CFR Part 50. The thickness of the liner plates is generally between 6.2 mm (1/4 in.) and 9.5 mm

(3/8 in.). The liner plates are attached to the concrete containment wall by stud anchors or structural

rolled shapes, or both. The design process assumes that the liner plates do not carry loads.

However, the anchorage system transfers normal loads, such as those from concrete shrinkage,

creep, and thermal changes, imposed on the concrete containment structure to the liner plates.

Internal pressure and temperature loads are directly applied to the liner plates. Thus, under designbasis conditions, the liner plates could experience significant strains.

The design may consider fatigue of the liner plates based on an assumed number of loading cycles

for the current operating term. The cyclic loads include containment building interior temperature

variation during the heatup and cooldown of the RCS, a LOCA, annual outdoor temperature

variations, thermal loads because of high-energy containment, penetration piping lines (e.g. steam

and feedwater lines), seismic loads, and pressurization from periodic Type-A integrated leak rate

tests.

The containment liner plates, penetration sleeves (including dissimilar metal welds), and penetration

bellows may be designed in accordance with the requirements of ASME B&PV Code, Section 1II. If

a plant's code of record requires a fatigue analysis, then this analysis may be a TLAA and must be

evaluated in accordance with 10 CFR 54.21 (c)(1) to ensure that the effects of aging on the intended

functions will be adequately managed for the period of extended operation.

4.6.1 Summary of Technical Information in the Application

The applicant discussed the evaluation of the containment liner in Section 4.6.1 of the LRA. The

applicant indicated that the containment liner plate was designed to withstand the following cyclic

loads:

* 40 cycles of annual outdoor temperature variations

* 200 cycles of containment temperature variations from plant startup and shutdown

* 1 cycle of containment temperature variation resulting from accident conditions

* 10 cycles of earthquake loads

The applicant indicated that the fatigue evaluation of the liner plate used an envelope of the design

loads. The applicant further showed that the number of allowed cycles for the enveloped design

load far exceeds the number projected for 60 years of plant operation.

The applicant discussed the evaluation of the containment penetrations in Section 4.6.2 of the LRA.

The applicant indicated that, although mechanical penetrations should have been designed to meet

the fatigue provisions of the ASME Code, the original stress analyses of most penetrations address

only pipe break loads. The applicant stated that recent analyses of the main steam and RHR

penetrations demonstrate that these penetrations satisfy the fatigue exemption provisions of ASME

Code, Section III, Paragraph N-415.1. The applicant stated that the number of design cycles used

in the evaluation of these penetrations is not expected to be exceeded during the period of extended

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-

operation. The applicant indicated that ASME Code, Section Xl, will manage fatigue cracking of the

remaining penetrations.

4.6.2 Staff Evaluation

RAM 4.6. 1-1

Section 4.6.1 of the LRA and Section 5.2.3 of the CNP UFSAR discuss the design of the liner plate.

The UFSAR indicated that the liner plate was designed for the cyclic loads as described by the

applicant in the LRA. In the LRA& the applicant indicated that the maximum calculated stress

resulting from design cyclic loads is relatively low, and, consequently, fatigue of the liner plate is not

a concern for the period of extended operation. The applicant also indicated that it evaluated the

liner in 1999 after the discovery of localized thinning of the liner. In RAI 4.6.1-1, the staff asked

the applicant to indicate the amount and extent of the localized liner thinning. The staff also

requested that the applicant describe how it performed the fatigue evaluation of the locally thinned

area.

The applicant's June 16, 2004, response indicated that corrosion pitting caused the localized

thinning. The observed pitting occurred behind the moisture barrier sealant material used to protect

the bottom liner from moisture intrusion in the annulus gap below the floor grade level. The

applicant indicated that the observed pitting in the Unit 1 liner exceeded the established acceptance

criteria that require a minimum liner plate wall thickness to be greater than 6.2 mm (1/4 in.). The.

applicant also indicated that the pitting was localized. The NRC documented its review of the

applicant's evaluation of the liner and corrective actions in NRC Inspection Reports

50-315/99026(DRS) and 50-316/99026(DRS). The reports conclude that the applicant's corrective

actions were adequate.

The applicant's response to RAI 4.6.1-1, indicates that the liner plate is capable of sustaining

180,000 cycles of an alternating stress of 20 kips per square inch (ksi). The value of 20 ksi is the

design stress limit for operating conditions specified in the UFSAR. The applicant performed a

simplified calculation of the maximum liner stress resulting from the design operating loads and

found that the calculated stress was significantly less than 20 ksi. On the basis of this assessment,

the applicant concluded that ample fatigue margin exists in the liner plate to accommodate the

observed pitting in the liner plate. The staff agrees with the applicant's qualitative assessment that,

considering the number of design cycles and the magnitude of.the operating stress range,

adequate fatigue margin should exist in the liner plate to accommodate the observed pitting.

Therefore, the staff finds that the applicant performed an acceptable assessment regarding the

fatigue life of the liner plate for the period of extended operation, pursuant to 10 CFR 54.21 (c)(1).

RAI 4.6.2-1

As stated previously, the applicant indicated that containment penetrations should satisfy the ASME

Code fatigue provisions. However, most of the containment penetration stress analyses address

only pipe break loads. The applicant stated that recent analyses of the main steam and RHR

penetrations demonstrate that these penetrations satisfy the fatigue exemption provisions of ASME

Code, Section 111, Paragraph N-415.1. The applicant proposed to manage the potential for fatigue

cracking of the remaining penetrations using ASME Code, Section Xl. However, the NRC staff has

not endorsed the use of the ASME Code, Section Xl, inspection program in lieu of meeting design4-21
L

basis fatigue limits for the period of extended operation. In RAI 4.6.2-1, the staff requested that the

applicant either propose a plant-specific fatigue AMP for the penetrations, in accordance with

10 CFR 54.21 (c)(1 )(iii), or provide an evaluation to demonstrate that the penetrations will be

acceptable for the period of extended operation, in accordance with 10 CFR 54.21 (c)(1 )(i) or

10 CFR 54.21 (c)(1)(ii).

In its June 16, 2004 response, the applicant committed to perform additional evaluations of the

containment penetrations before the period of extended operation. The applicant proposed to

evaluate containment penetration groups that have similar cyclic loads to demonstrate that these

penetration groups satisfy the fatigue exemption provisions of ASME Code, Section III, Paragraph N-415.1. The applicant also committed to perform a fatigue analysis of the limiting penetration for

any penetration group that does not satisfy the fatigue exemption rules. The fatigue analysis will be

projected to the end of the period of extended operation. This is Commitment # 34 in Appendix A of

this SER. The applicant's commitment resolves RAI 4.6.2-1.

4.6.3 UFSAR Supplement

The applicant provided a UFSAR Supplement describing its TLAA evaluation for the containment

liner plate and penetration fatigue analyses in Section A.2.2.4 of the LRA. The staff requested that

the applicant updating the UFSAR Supplement to reflect its commitment to analyze the containment

penetrations. The staff identified this as Confirmatory Item 4.6-1. The applicant's January 21, 2005,

response provided the updated UFSAR Supplement for Section A.2.2.4. The updated UFSAR

Supplement contains a discussion of the applicant's commitment to analyze the containment

penetrations. This is part of Commitment # 34 in Appendix A of this SER. The staff concludes that

the revised UFSAR Supplement adequately describes the applicant's actions to address the

containment liner plate and penetration fatigue analyses. Therefore, Confirmatory Item 4.6-1 is

closed.

4.6.4 Conclusions

The staff has reviewed the applicant's TLAA of the containment liner and penetrations and

concludes that the applicant's actions and commitments satisfy the requirements of

10 CFR 54.21 (c)(1 )(i). The staff has also reviewed the UFSAR Supplement and finds that the

applicant's revised UFSAR Supplement provides a sufficient description of the containment liner and

penetration fatigue TLAA to satisfy the requirements of 10 CFR 54.21 (d).

4.7 Other Plant-Specific Time-Limited Aging Analyses

Other CNP-specific TLAAs include the following:

* leak-before-break analyses

* thermal aging evaluation of the RCP casing

* ice condenser lattice frame fatigue analysis

* underclad cracking

* steam generator flow-induced vibration analysis

* fatigue analysis of cranes

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4.7.1 Reactor Coolant System Piping Leak Before Break

4.7.1.1 Summary of Technical Information in the Application

The applicant stated that it had performed a leak-before-break (LBB) analysis for the CNP RCS

primary loop and the pressurizer surge line. The analysis considered the thermal aging of cast

austenitic stainless steel (CASS) piping and the fatigue transients that drive the flaw growth over the

operating life of the plant.

4.7.1.2 Staff Evaluation

The applicant completed a TLAA evaluation of the RCS primary loop piping LBB analyses, and

WCAP-1 5131 documents the evaluation. First, the applicant considered how time would impact the

material properties of CASS. The CASS used in the RCS is subject to thermal aging during

service. Thermal aging causes an elevation in the yield strength of the material and a decrease in

the fracture toughness. The decrease in fracture toughness is proportional to the level of ferrite in

the material. -Thermal aging in these stainless steels will continue until a saturation or fully aged

point is reached. The applicant stated that Section 4.3 of WCAP-1 5131 addresses the fracture

-toughness properties of statically and centrifugally cast CF8M stainless steel. The fracture

toughness data from NUREG/CR-6177 was used to calculate the J value for both pipes and elbows.

The analysis supporting LBB relied on fully aged stainless steel material properties, and, therefore,

the applicant concluded that the analysis does not have a material property time-dependency that

requires further evaluation for license renewal.

Second, the applicant considered how time would influence the accumulation of actual fatigue

cycles that could invalidate the fatigue crack growth analysis reported in WCAP-1 5131. The

applicant stated that it had performed a fatigue crack growth analysis of the reactor vessel inlet

nozzle safe-end region to determine its sensitivity to the presence of small cracks. It selected the

nozzle safe-end connection because crack growth calculated at this location is representative of the

entire primary loop.

The nozzle safe-end connection configuration includes an SA 508 Class 2 or 3 stainless steel clad

nozzle connected to a stainless steel safe end by a nickel-based alloy weld. The applicant obtained

the fatigue crack growth rate laws for the stainless steel clad LAS nozzle from ASME Code, Section

Xl. Fatigue crack growth rate laws for stainless steel and Alloy 600 in a PWR environment were

developed based on available industry literature. The applicant stated that had it evaluated the

crack growth rate laws for the reactor transients presented in WCAP-1 5131, Table 8-1, which are

bounded by the fatigue design transients defined in Table 4.1-10 of the UFSAR.

The applicant completed its review of the RCS fatigue transient cycle definitions presented in Table

4.1-10 of the UFSAR and found in all instances that the RCS design transients originally defined for

40 years are acceptable for 60 years of operation. In addition, the continued implementation of the

Fatigue Monitoring Program provides reasonable assurance that the fatigue crack growth analysis

reported in WCAP-15131 will remain valid during the period of extended operation. Based on the

information provided above, the staff concludes that the LBB TLAA will remain valid for the period of

extended operation, in accordance with 10 CFR 54.21 (c)(1 )(i), and is therefore acceptable.

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The applicant also completed a TLAA evaluation of the pressurizer surge line LBB analyses,

described in WCAP-15435. The applicant stated that the report demonstrates compliance with the

LBB criteria for the pressurizer surge line piping based on plant specific analysis. The surge line

piping is fabricated from A376, Type 316, wrought austenitic stainless steel, and is not susceptible to

reduction of fracture toughness by thermal aging. The applicant reviewed WCAP-15435 and

determined that the only analysis consideration that could be influenced by time is the accumulation

of actual fatigue transient cycles that could invalidate the fatigue crack growth analysis reported in

Section 6.0 of WCAP-15435. A fatigue crack growth analysis was performed for a plant similar to

CNP, Units 1 and 2, which evaluated two locations. The results of the analysis indicate that the

maximum fatigue crack growth for 40 years is acceptable by ASME Code, Section Xl, acceptance

standards. Because the pressurizer pipe size, pipe schedule, and pipe materials are the same, and

the design transients are identical to the plant used in the analysis, the applicant concluded that

CNP, Units 1 and 2, pressurizer surge lines will have similar crack growth. The applicant evaluated

the crack growth formulations reported in WCAP-1 5435 for CNP fatigue design transients defined in

Table 4.1-10 of the UFSAR.

The applicant concluded that the results of the RCS transient cycle definition review determined that

in all instances the RCS design transients originally defined for 40 years are acceptable for 60 years

of operation. Additionally, the applicant considered that the continued implementation of the Fatigue

Monitoring Program provides reasonable assurance that the fatigue crack growth analysis reported

in WCAP-1 5435 will remain valid for the period of extended operation. The applicant also stated

that the NRC SE of WCAP-1 5435 relied on the applicant's demonstration that the leakage detection

system inside containment could reliably detect 0.8 gallons per minute of primary leakage. In

December 2000, an NRC inspection reviewed the engineering evaluation to verify that the radiation

monitoring system in the lower containment can detect this leakage using particulate detectors. The

applicant stated that the inspection resulted in no significant findings.

4.7.1.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include an UFSAR

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

and the evaluation of TLAAs for the period of extended operation. The applicant provided an

UFSAR Supplement summary description TLAA of the RCS piping LBB in LRA Section A.2.2.5. On

the basis of its review, the staff concluded the UFSAR Supplement summary adequately describes

the TLAA of the RCS piping LBB and is therefore acceptable.

4.7.1.4 Conclusion

The properties for the cast stainless steel piping material are acceptable because they will not

degrade below the fully aged properties in the extended period of operation. The applicant

established the Fatigue Monitoring Program to assure that the number of cycle counts for a

transient set does not exceed its cycle limits. Therefore, the staff concludes that the applicant has

provided an acceptable TLAA regarding LBB and meets the requirements of 10 CFR 54.21 (c)(1)(i).

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4.72 ASME Code Case N-481

4.7.2.1 Summary of Technical Informnation in the Application

The applicant stated that it performed a demonstration of compliance of the primary loop CASS'

pump casings with ASME Code Case N-481 for CNP, Units 1 and 2. The CNP analysis considered

thermal aging and fatigue crack growth of the CASS pump casings. The applicant stated that these

analyses meet the definition of a TLAA.

4.7.2.2 Staff Evaluation

The applicant stated that a demonstration of compliance of the primary loop pump casings with

ASME Code Case N-481 was evaluated generically for all Westinghouse plants in WCAP-13045,

"Compliance to ASME Code Case N-481 of the Primary Loop Pump Casings of Westinghouse Type

Nuclear Steam Supply Systems." Further, WCAP-1 3128, "Demonstration of Compliance of the

Primary Loop Pump Casings of D. C. Cook Units 1 and 2 to ASME Code Case N-481," presents a

CNP-specific Code Case N-481 evaluation. The CNP analysis references the generic evaluation of

Code Case N-481 provided in WCAP-13045. WCAP-13128 finds that time influences the thermal

aging of the CASS pump casings and fatigue crack growth. Therefore, the applicant considered the

Code Case N-481 analysis as a potential TLAA at CNP.

RAI 4.7.2.1-1

The applicant's TLAA for ASME Code Case N-481 did not indicate whether the NRC reviewed and

approved the generic WCAP-1 3045 or the CNP-specific WCAP-1 3128. Therefore, in RAI 4.7.2.1-1,

the staff asked the applicant to do the following:

Provide documentation which identifies that the NRC staff reviewed and approved

WCAP-1 3045 and WCAP-1 3128. If the reports were not previously submitted, then

the applicant is requested to submit WCAP-1 3045 and WCAP-1 3128 for NRC

review and approval.

In its supplemental letter dated June 16, 2004, the applicant's response to RAI 4.7.2.1-1 stated that

WCAP-1 3045 provides information to demonstrate compliance with item (d) of ASME Code Case

N-481 on a generic basis for all Westinghouse design primary loop pump casings' The applicant

stated that a variety of pump casing models, loads, and materials exist, and it is not feasible to

specifically qualify each plant of Westinghouse design. -Instead, it set up enveloping or bounding

criteria whereby a specific utility need only show that the loads of the pump casings of interest fall

under the umbrella loads established by the analysis.

WCAP-1 3128 includes the CNP-specific nonproprietary information from WCAP-1 3045 necessary

to support the generic conclusions of the report. The applicant explained that WCAP-13128

qualified the primary loop pump casings of CNP, Units 1 and 2, to item (d) of ASME Code Case N481 by evaluation:-The applicant stated that the North Anna Power Station, Unit 2, also used this

same approach as an appendix to its ISI plan for the third inspection interval dated June 30, 2001.

The staff concludes that the applicant's response to RAI 4.7.2.1-1 is acceptable. The staff

considers RAI 4.7.2.1-1 closed.

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In WCAP-1 3128, the applicant evaluated the material properties of CASS. The applicant stated that

CASS is used in the RCS and is subject to thermal aging during service, as discussed in Section

4.7.1.1 of the LRA. The analysis reported in WCAP-13128 supporting ASME Code Case N-481

relied on fully aged stainless steel material properties. Therefore, the applicant concluded that the

analysis does not have a material property time-dependency that would require further evaluation for

license renewal.

The applicant also completed a stability evaluation of the RCP and concluded that the accumulation

of actual fatigue transient cycles over time could invalidate the stability evaluation reported in

WCAP-13045, Section 12.0, including Table 12.2. The applicant stated that the Fatigue Monitoring

Program, which is discussed in Appendix B to the LRA, monitors thermal fatigue design transients

(including the transient cycle assumptions reported in WCAP-1 3045, Table 12-2) for the period of

extended operation. The applicant concluded that the continued implementation of the Fatigue

Monitoring Program will provide reasonable assurance that the evaluation results reported in

WCAP-13128 will remain valid during the period of extended operation. Therefore, the fatigue

growth analysis will remain valid for the period of extended operation, in accordance with

10 CFR 54.21 (c)(1)(i).

4.7.2.3 UFSAR Supplement

As required by 10 CFR 54.21 (d), applicants for license renewal must include an UFSAR

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

and the evaluation of TLAAs for the period of extended operation. The applicant provided an

UFSAR Supplement summary description of TLAA regarding ASME Code Case N-481 in LRA

Section A.2.2.5. On the basis of its review, the staff concluded the UFSAR Supplement summary

adequately describes the TLAA regarding ASME Code Case N-481 and is therefore acceptable.

4.72.4 Conclusion

The staff has reviewed the information provided in Section 4.7.2 of the LRA, as supplemented by

the applicant's response to RAI 4.7.2.1 -1 in its letter dated June 16, 2004. This review finds that

the applicant demonstrated the compliance of the primary loop CASS pump casings material with

ASME Code Case N-481 because the casings will not degrade below the fully aged properties in

the extended period of operation.- The applicant established the Fatigue Monitoring Program that

monitors thermal fatigue design transients and assures that the number of cycle counts for a

transient set does not exceed cycle limits. Therefore, the staff concludes that the applicant has

provided an acceptable TLAA regarding ASME Code Case N-481 and meets the requirements of

10 CFR 54.21 (c)(1)(i).

4.7.3 Ice Condenser Lattice Frame

4.7.3. 1 Summary of Technical Information in the Application

In Section 4.7.3 of the LRA, the applicant provided a TLAA related to the ice condenser lattice

frames (ICLFs) for Units 1 and 2. The applicant indicated that UFSAR Table 5.3.5.3-2 shows the

results of fatigue analysis. The applicant explained that the UFSAR analysis is based on 400

operational basis earthquakes (OBEs). Based on the operating experience at CNP and other

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facilities, this OBE limit will not be surpassed during the period of extended operation, in accordance

with 10 CFR 54.21 (c)(1 )(i).

4.7.3.2 Staff Evaluation

In addition to the review of Section 4.7.3 of the LRA, the staff reviewed Table 3.5.2-1 and the

Structures Monitoring Program to see if the applicant addressed aspects related to aging

management of ICLF components. The applicant's fatigue analysis only considers the gross

effects of number of cycles of OBEs on ICLFs. The staff finds the TLAA related to the number of

OBE cycles acceptable, as the number of OBE cycles should be well below 400 throughout the end

of the extended period of operation. -

However, the LRA does not address the following:

* the operating experience related to the condition of ICLFs

* the effects of borated ice on the ICLF components

* the effects of sustained low temperatures

* fatigue resulting from the number of cycles of temperature transients on the ICLF

components.

RAI 4.7.3-1

Therefore, in RAI 4.7.3-1, dated May 7, 2004, the staff stated the following:

A line item in Table 3.5.2-1 (page 3.5-31) of the LRA, states that the aging effect

considered for ICLF is "loss of material," and that it is monitored under Structural

Monitoring Program (SMP). A review of the SMP in Section B13.32 of the LRA

indicates that the program is consistent with Section XI.S6 of NUREG-1 801.

NUREG-1 801 does not specifically incorporate the aging management of the

components of ice condensers. In order to complete the review of this TLAA, the

staff requested that the applicant provide the following information:

(a). A summary of operating experience related to the condition of ICLF

components (out of plumb support columns, lattice frame spacing

adjustments, maintenance of hydraulic radius, etc.).

(b) An assessment of the effects of borated ice and low sustained temperature

on ICLF components.

(c) Justification for not considering the fatigue analysis TLAA for the effects of

temperature variation on the ICLF components.

In its response to item (a), dated June 16, 2004, the applicant stated the following:

A search of the electronic corrective action program database for plant specific

operating experience over the past five years found only one CR that was related to

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the condition of the ice condenser lattice frame structural components. The CR

documented damage to ice condenser lattice guide/spacer bars. No CRs were

identified pertaining to loss of material or other aging effects for these components. The CR evaluation determined that the bent spacers resulted from maintenance

activities while attempting to free frozen ice baskets. In addition, an operating experience review performed during the integrated plant assessment process did not

identify aging effects as a problem for ice condenser lattice frame components.

The staff finds that the applicant's operating experience does not indicate any significant age-related degradation that requires specific attention during the period of extended operation. Moreover, the

applicant monitors the aging effects under its Structures Monitoring Program.

In its response to item (b), dated June 16, 2004, the applicant provided the following information:

The ice condenser environment is maintained between -12 OC (10 OF) and -6.7 OC

(20 OF) with very low absolute humidity. In this environment, the ice condenser

lattice frame components are not susceptible to corrosion. The materials of ice

condenser construction were selected to be effectively inert under all conditions of

operation of the ice condenser. The ice condenser lattice frame structural sections, plates and bar flats, are made of high-strength low-alloy weathering grade steel, meeting the requirements of ASTM A441, Standard Specification for High-Strength Low-Alloy Structural Manganese Vanadium Steel. Weathering steel exhibits

excellent corrosion resistance. Consequently, the aging effects of borated ice and

low sustained temperature on the ice condenser lattice frames are expected to be

insignificant. This determination is substantiated by CNP operating experience. *However, loss of material is conservatively considered an aging effect requiring

management.

Based on the material of construction of the ICLFs and demonstration that the ICLF has not

experienced loss of material, the staff concurs with the applicant's approach to monitor the age- related degradation of ICLF components, including the effects of low temperature cycles and

borated ice during the period of extended operation.

In its response to item (c), dated June 16, 2004, the applicant provided the following information:

The lattice frame is designed according to American Institute of Steel Construction

(AISC) AISC 69, Specification for Design, Fabrication, and Erection of Structural

Steel for Buildings. The design loading conditions for the lattice frames are specified in UFSAR Section 5.3.4.2 and include dead weight, live loads, thermal-induced

loads, seismic, and DBA loads transferred to the columns by the intermediate deck

and doors. The ambient temperature variation under normal operating conditions is

-12 0C (10 OF).

The fatigue evaluation of the lattice frame was conducted in accordance with AISC

69, Appendix B. Thermal loads due to the maximum temperature are considered in

the evaluation of maximum stresses reported in UFSAR Table 5.3.5.3-1, as required by AISC 69.

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The fatigue stresses applicable to the lattice frame due to 400 operating basis

earthquake (OBE) cycles were determined to be below the allowable range of stress

defined by AISC 69, as indicated in UFSAR Table 5.3.5.3-2. Due to the relatively

low magnitude of repeated temperature variations, thermally induced loads are less

limiting than OBE loads when considering repeated variations of loads on the

structure (fatigue).

Based on the applicant's responses to items (a), (b), and (c), above, the staff concludes that the

applicant will appropriately manage the aging of the ICLF components during the extended period of

operation..

4.7.3.3 UFSAR Supplement

As required by 10 CFR 54.21(d), applicants for license renewal must include an UFSAR

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

and the evaluation of TLAAs for the period of extended operation. The applicant provided an

UFSAR Supplement summary description of the TLAA of ICLF components in LRA Section A.2.2.5.

On the basis of its review, the staff concluded the UFSAR Supplement summary adequately

describes the TLAA of ICLF components and is therefore acceptable.

4.7.3.4 Conclusion

Based on the staff's review of Section 4.7.3 of the LRA and the applicant's response to the RAI, the

staff concludes that the existing fatigue analysis is valid for the ICLF members, in accordance with

10 CFR 54.21 (c)(1)(i). Based on the applicant's commitment to monitor the ICLF members under

its Structures Monitoring Program, the staff also concludes that the ICLF members will be able to

perform their intended function during the period of extended operation.

4.7.4 Reactor Vessel Underclad Cracking

4.7.4.1 Summary of Technical Information in the Application

In 1970, examination of Nucleoelectrica Argentina SA's Atucha-1 reactor vessel first detected

intergranular separations (underclad cracking) in LAS, heat-affected zones under austenitic

stainless steel weld claddings in SA-508, Class-2, reactor vessel forgings. Such separations have

been reported in SA-508, Class 2, reactor vessel forgings manufactured to a coarse-grain practice

and clad by high-heat input submerged arc processes. The regulatory position regarding this issue,

found in RG 1.43, 'Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components,"

issued May 1973, states that detection of underclad cracks unormally requires destructively

removing the cladding to the weld fusion line and examining the exposed base metal either by

metallographic techniques or with liquid penetrant or magnetic particle testing methods."

WCAP-7733, "Reactor Vessels Weld Cladding-Base Metal Interaction," in which Westinghouse

presents a fracture mechanics analysis to justify continued operation of Westinghouse units for 32

EFPYs with underclad cracks in the RPVs, provides a detailed analysis of underclad cracks. The

WOG and the NRC identified the analysis reported in WCAP-7733 as a TLAA requiring evaluation

for license renewal. The WOG subsequently evaluated the impact of cracks beneath austenitic

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stainless steel weld cladding on RPV integrity in WCAP-15338, which the NRC approved in July

2002 to include all Westinghouse plants.

The CNP reactor vessels do not contain SA 508, Class 2, forgings in the beltline regions. Only the

vessel and closure head flanges and inlet and outlet nozzles are fabricated from SA 508, Class 2,

forgings. The evaluation contained in WCAP-1 5338 has been used to demonstrate that fatigue

growth of the subject flaws will be minimal over 60 years and the presence of the underclad cracks

are of no concern relative to the structural integrity of the vessels.

Table 4.1-10 of the UFSAR reports the design transients for CNP. The numbers of design cycles

and transients assumed in the WCAP-1 5338 analysis bound the numbers of design cycles and

transients projected for 60 years of operation. The UFSAR Supplement, which is Appendix A to the

application, provides a summary description of the evaluation of the TLAA for reactor vessel

underclad cracking.

Therefore, the applicant concluded that the analysis of underclad cracking for CNP would remain

valid for the period of extended operation, in accordance with 10 CFR 54.21 (c)(1)(i).

4.7.4.2 Staff Evaluation

Underclad cracks, first discovered in October 1970 during examination of the Atucha reactor vessel,

have been reported to exist only in SA-508, Class 2, RPV forgings manufactured with a coarsegrain microstructure and clad by high-heat input submerged arc welding processes. WCAP-7733

first addresses the underclad cracking issue and justifies the continued operation of Westinghouse

plants for 32 EFPYs. Subsequently, Westinghouse submitted WCAP-15338-A, which extends the

analysis to justify operation of Westinghouse plants for 60 years of plant operation. The staff

providesdits review of WCAP-1 5338-A in a September 25, 2002, letter to R.A. Newton concluding

that LRAs should include the following two action items:

(1) The license renewal applicant should verify that its plant is bounded by the WCAP-1 5338-A

report. Specifically, the renewal applicant should indicate whether the number of design

cycles and transients assumed in the WCAP-1 5338-A analysis bounds the number of cycles

for 60 years of operation of its RPV.

(2) As required by 10 CFR 54.21 (d), a UFSAR Supplement for the facility must contain a

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

the evaluation of the TLAA for the period of extended operation. Those applicants fQr

license renewal referencing the WCAP-1 5338-A report for the RPV components must

ensure that the UFSAR Supplement summarizes the evaluation of the TLAA.

RAI 4.74-1

The NRC SE for WCAP-1 5338-A requires the applicant to verify that its plant is bounded by the

values in the report. In LRA Section 4.7.4, the applicant stated that the number of design cycles and

transients assumed in the WCAP-1 5338-A analysis bounds the number of design cycles and

transients for CNP units for 60 years. The applicant did not, however, explain how it arrived at this

conclusion. The NRC requested this information in RAI 4.7.4-1. The applicant responded in a letter

dated September 2, 2004, that, except for the feedwater cycling at hot shutdown, it has verified that

the design transients assumed in WCAP-15338-A bound the types and numbers of RCS design

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transients for 60 years, as shown in LRA Table 4.3-1. The feedwater cycling at hot shutdown

transient is associated with a concern about feedwater nozzle cracking and is not monitored at the

CNP units because of design and operating modifications to preclude feedwater nozzle cracking.

The staff considers the response acceptable because the types and numbers of CNP RCS design

transients for 60 years are appropriate as discussed in Section 4.3 of this SER, and the applicant

has satisfied action item 1 of the SE for WCAP-15338-A discussed above, demonstrating that'the

types and numbers of CNP RCS design transients for 60 years are bounded by those'assumed in

WCAP-1 5338-A. High-cycle-fatigue initiation and low-cycle-fatigue growth caused feedwater nozzle

cracking. By the mid-1 980s, design and operating modifications that precluded feedwater nozzle

cracking had resolved this generic issue which affected feedwater Iiner radii and spargers.

Therefore, the staff agrees with the applicant that the CNP units need not monitor the feedwater

cycling at hot shutdown transient for the concern of underclad cracking and determines that the

conclusions of WCAP-1 5338-A apply to the CNP units. Therefore, RAI 4.7.4-1 is closed.

4.7.4.3 UFSAR Supplement

As required by 10 CFR 54.21 (d), applicants for license renewal must include an UFSAR

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

and the evaluation of TLAAs for the period of extended operation. The applicant provided an

UFSAR Supplement summary description of the TLAA for RPV underclad cracking in LRA Section

A.2.2.5. On the basis of its review, the staff concluded the UFSAR Supplement summary

adequately describes the TLAA for RPV underclad cracking and is therefore acceptable.

4.7.4.4 Conclusion

The staff reviewed the TLAA regarding the structural integrity of the CNP RPVs with assumed

underclad cracking during the period of extended operation. The staff determined that the

conclusions of WCAP-15338-A apply to the CNP RPVs and the flaw growth resulting from 60 years

of operation will not result in the loss of integrity of the CNP RPVs to the end of the period of

extended operation. Therefore, this analysis satisfies the requirements of 10 CFR 54.21 (c)(1)(i).

4.7.5 Steam Generator Tube Flow-induced Vibration

4.7.5.1 Summary of Technical Information in the Application

In the LRA, the applicant identified analyses of steam generator tube flow-induced vibrations (FIVs)'

as a TLAA. The steam generators were replaced in 2000 for Unit 1 and 1988 for Unit 2.' The

applicant's analyses were based on the use of fretting wear damage parameters and corrosion

allowance assumptions for Unit 1 and tube wear allowance assumptions for Unit 2. The analyses for

Units 1 and 2 remain valid for the period of extended operation in accordance with

10 CFR 54.21 (c)(1)(i).

4.7.5.2 Staff Evaluation

The original steam generators were replaced in 2000 for Unit 1 and 1988 for Unit 2. The applicant

analyzed flow-induced vibrations as part of the steam generator analysis for license renewal. In

response to RAI 4.7.5-1, the applicant stated that different assumptions were made for FIV analyses

performed by two different vendors. The Unit 1 FIV analysis is based on a 40-year design life,

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L.

extending to 2040, which surpasses the period of extended operation. For Unit 2, the assumption -

for wear allowance was based on designed set of operating transients which are monitored through

the Fatigue Monitoring Program. In Section A.2.2.2 of the LRA, the applicant states that the

assumed number of RCS design transients is acceptable for 60 years. Steam generators are

designed to limit tube degradation resulting from FIV. 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 AVBs and other supports with the tubes.

The applicant further states in their response that the Steam Generator Integrity Program, which is

based on NEI 97-06, "Steam Generator Program Guidelines," and the Water Chemistry Control

Program, which is based on EPRI guidelines TR-105714, Revision 4 and TR-102134, Revision 5,

manage the aging effect of loss of material of steam generator tubes and tubes support

components. This includes loss of material by the aging mechanisms of corrosion and wear.

Despite operating experience showing that corrosion and wear rates of steam generator tubes can

exceed the rates predicted by these analyses, the staff agrees with the applicant that the Water

Chemistry Program and periodic inspections as required by the Steam Generator Tube Integrity

Program will manage these aging, effects. These periodic inspections will monitor and detect any

potential aging effects resulting from corrosion and tube wear. These programs are consistent with

the AMP descriptions in the GALL Report and are acceptable. Staff evaluations of these AMPs and

aging effects appear in Sections 3.0.3.2.15, 3.0.3.1, and 3.1.2.3.5 of this SER. The staff therefore

concludes that tube corrosion and wear in CNP are not TLAAs.

4.75.3 UFSAR Supplement

The applicant provided the UFSAR Supplement summary descriptions for the TLAA on the Steam

Generator Tubes - Flow Induced Vibration in Section A.2.2.5 of Appendix A to the LRA. The staff

reviewed the UFSAR Supplement summary descriptions for the TLAA, as given in Section A.2.2.5

of Appendix A to the LRA. The staff determined that the steam generator FIV analysis may not be

considered a TLAA because other periodic inspections programs can better manage the aging

effects of tube corrosion and wear; therefore, the UFSAR description of the FIV analysis is not

required.

4.7.5.4 Conclusion

The staff concludes that the flow-induced vibration analysis for the replacement steam generators

may not be considered a TLAA issue as defined in 10 CFR 54.3(a)(3). The applicant will

adequately manage the effects of aging on the pressure boundary function for the period of

extended operation through periodic inspections required by the applicant's Steam Generator

Integrity Program.

4.7.6 Fatigue Analysis of Cranes

The following types of cranes within the scope of license renewal were designed in accordance with

the guidance contained in NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants":

* containment polar cranes

* auxiliary building cranes

* screen house crane

4-32

I
According to NUREG-0612, the design of heavy-load, overhead handling systems must meet the

intent of the Crane Manufacturers Association of America (CMAA) Specification Number 70, -

"Specifications for Electric Overhead Traveling Cranes." Overhead cranes designed to CMAA-70

have an implicit fatigue design basis equivalent to a limiting number of 100,000 load cycles.

4.7.6.1 Summary of Technical Information in the Application

In response to NUREG-0612, the applicant stated that the polar cranes, auxiliary building cranes,

and screen house crane were in compliance, with limited exceptions, with the design standards of

CMAA-70. Conservative estimates of the number of cycles that could be achieved in 60 years of

operation for these five cranes do not exceed the limit in CMAA-70. Therefore, the applicant

contended that the crane designs will remain valid for the period of extended operation, in

accordance with the requirements of 10 CFR 54.21 (c)(1 )(i).

4.7.6.2 Staff Evaluation

The NRC approved the applicant's response to NUREG-0612 in an SE dated September 20, 1983.

Based on a review of the estimate of the number of load cycles projected for 60 years of operation

for the above listed cranes, the staff finds that these canes will meet the load cyclic requirements of

CMAA-70 with adequate safety margins. Therefore, the applicant has demonstrated that the TLAAfor the current operating term remains valid for the period of extended operation.

4.76.3 UFSAR Supplements

As required by 10 CFR 54.21(d), applicants for license renewal must include an UFSAR

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

and the evaluation of TLAAs for the period of extended operation. -The applicant provided an -- t

UFSAR Supplement summary description of the fatigue load cycles TLAA for cranes in LRA Section

A.2.2.5. On the basis of its review, the staff concluded the UFSAR Supplement summary

adequately describes the fatigue load cycles TLAA for cranes and is therefore acceptable.

4.7.6.4 Conclusions

The staff has reviewed the applicant's crane loads fatigue cycles TLAA and concludes that the

applicant's actions and commitments satisfy the requirements of 10 CFR 54.21 (c)(1).

4.7.7 Reactor Coolant Pump Flywheels

4.7.7.1 Summary of Technical Information in the Application

The applicant stated that it performed a TLAA on the RCP flywheels. It identified the aging effect of

concern to be fatigue crack and growth in the flywheel bore keyway resulting from stresses caused

by starting the motor.

4.7.7.2 Staff Evaluation

The applicant stated that the RCP motors are large, vertical, squirrel-cage, induction motors. The

motors have flywheels to increase rotational inertia, thus prolonging pump coastdown and assuring

4-33.
a more gradual loss of main coolant flow to the core in the event that pump power is lost. The

applicant stated that the flywheel is mounted on the upper end of the rotor, below the upper radial

bearing and inside the motor frame. The applicant identified the aging effect of concern as fatigue

crack initiation and growth in the flywheel bore keyway from stresses resulting from starting the

motor.

The applicant stated that it submitted a license amendment request in 1996 to reduce the RCP

flywheel inspection frequency and scope based on WCAP-1 4535. This topical report includes a

stress and fracture evaluation that addresses fatigue crack growth for 60 years. The applicant also

stated that the NRC approved the license amendment requests for CNP, Units 1 and 2, by means

of License Amendments 217 and 201.

Since the analysis of fatigue crack initiation and growth in WCAP-14535 is based on a 60-year term,

in accordance with 10 CFR 54.21 (c)(1)(i), the analysis is acceptable for the extended period of

operation.

4.7.7.3 UFSAR Supplement

Section A.1.2, page A-B, of Appendix A to the LRA provides a UFSAR summary description of the

RCP flywheel TLAA, as required by 10 CFR 54.21(d). It indicates that the existing analysis is valid

for the period of extended operation and is consistent with the staff's evaluation discussed in Section

4.7.7.2 of this SER. On the basis of its review, the staff concludes the UFSAR Supplement

summary adequately describes the TLAA of RCP flywheels and is therefore acceptable.

4.7.7.4 Conclusions

The RCP flywheels are acceptable because the applicant has demonstrated that fatigue crack

growth in the flywheel bore keyway from stresses resulting from starting the motor will not exceed

the ASME Code requirements during the extended period of operation. In August 1997, the NRC

reviewed and approved WCAP-14535, which provided a stress and fracture evaluation that

addressed fatigue crack growth for 60 years. Therefore, the staff concludes that the applicant has

provided an acceptable TLAA for RCP flywheels and meets the requirements of

10 CFR 54.21 (c)(1)(i).

4.8 Conclusions for TLAAs

The staff reviewed the information in Section 4 of the LRA. On the basis of its review, the staff

concludes that the applicant provided an adequate list of TLAAs, as defined in 10 CFR 54.3.

Further, the staff concludes that the applicant has demonstrated the following:

* The TLAAs will remain valid for the period of extended operation, as required by

10 CFR 54.21 (c)(1)(i).

* The TLAAs have been projected to the end of the period of extended operation, as

required by 10 CFR 54.21 (c)(1)(ii).

* The aging effects will be adequately managed for the period of extended operation, as

required by 10 CFR 54.21(c)(1)(iii).

4-34
In addition, the staff concludes that there are no plant-specific exemptions in effect that are based

on TLAAs, as required by 10 CFR 54.21 (c)(2). On this basis, the staff concludes that the structures

and components subject to TLAAs will perform their intended functions in accordance with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

4-35
5. REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

The NRC staff issued its Safety Evaluation Report (SER) with Open Items related to the renewal of

operating license for the Donald C. Cook Nuclear Plant (CNP), Units 1 and 2, on December 21,

2004. On February 9, 2005, the applicant presented its license renewal application, and the staff

presented its review findings to the Advisory Committee on Reactor Safeguards (ACRS) Plant

License Renewal Subcommittee. The staff reviewed the applicant's comments on the SER with

Open Items and completed its review of the license renewal application. The staff's evaluation is

documented in an SER that was issued by letter dated May 29, 2005.

During the 5241-meeting of the ACRS, July 6-8, 2005, the ACRS completed its review of the CNP

license renewal application and the NRC staff's SER. The ACRS documented its findings in a letter

to the Commission dated July 18, 2005. A copy of this letter is provided on the following pages of

this SER Section.

5-1
--I

July 18, 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 THE DONALD C. COOK NUCLEAR PLANT, UNITS I AND 2

Dear Chairman Diaz:

During the 524th meeting of the Advisory Committee on Reactor Safeguards, July 6-8, 2005, we

completed our review of the license renewal application for the Donald C. Cook Nuclear Plant

(CNP), Units 1 and 2, and the final Safety Evaluation Report (SER) prepared by the NRC staff. Our

Plant License Renewal Subcommittee also reviewed this matter during a meeting on February 9,

2005. During these reviews, we had the benefit of discussions with representatives of the NRC staff

and Indiana Michigan Power Company, the applicant. 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 committed to and established by the applicant to manage age-related

degradation provide reasonable assurance that CNP Units 1 and 2 can be operated in

accordance with their current licensing basis for the period of extended operation without

undue risk to the health and safety of the public.

2. The Indiana Michigan Power Company's application for renewal of the operating licenses for

CNP Units 1 and 2 should be approved.

BACKGROUND AND DISCUSSION

CNP Units 1 and 2 are Westinghouse pressurized water reactors with ice condenser containment

buildings. Licensed power output is 3304 MWt for Unit 1 and 3468 MWt for Unit 2. The Indiana

Michigan Power Company requested renewal of the operating licenses of Units 1 and 2 for 20 years

beyond their current license terms, which expire on October 25, 2014 and December 23, 2017,

respectively.

In the final SER, the staff documented its review of the license renewal application and other

information submitted by the applicant and obtained during the staff's audits and inspections at the

plant site. The staff reviewed the completeness of the applicant's identification of structures,

5-2
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 time-limited aging analyses (TLAAs).

The CNP application demonstrates consistency with, or justifies deviations from, the approaches

specified in the Generic Aging Lessons Learned Report.

During its review, the staff identified several components that should have been included in the

scope of license renewal. The applicant brought them into scope. With these inclusions, the staff

concluded that the applicant's scoping and screening processes have successfully identified the

SSCs within the scope of license renewal and subject to an aging management review. We agree.

The applicant performed a comprehensive aging management review of all SSCs within the scope

of license renewal. The application contains descriptions of 46 aging management programs for

license renewal, including existing, enhanced, and new programs. We agree with the staff's

conclusion that these programs are adequate and consistent with accepted practices for aging

management.

To be effective, the aging management programs need to be appropriately implemented. During

the aging management program inspections, the staff found that walkdowns performed as part of

the System Walkdown Program were not conducted quarterly as stated in the license renewal

application. Also, the applicant noted that it had not evaluated two coupons from the Boral -

Surveillance Program. This program monitors the performance of absorber materials in the spent

fuel pool by periodically measuring the physical and chemical properties of coupon samples that

receive a higher radiation dose than the functional boral panels. The applicant has implemented

corrective actions to ensure that the commitments will not be missed in the future.

The applicant identified and reevaluated systems and components requiring TLAAs for 20 more

years of operation. Analyses of reactor vessel neutron embrittlement (upper shelf energy,

pressurized thermal shock screening criteria, and pressure-temperature limits) performed by the

applicant and independently verified by the staff demonstrate that the limiting reactor vessel beltline

materials will satisfy the acceptance criteria for the period of extended operation.

The applicant showed that the current fatigue analysis of the ice condenser lattice frame, which

conservatively assumes 400 operating basis earthquakes, bounds 60 years of operation. This

analysis also bounds the effects of loads due to temperature fluctuations. The Structures

Monitoring Program manages aging of this structure. Operating experience indicates that the lattice

frame is not subject to significant age-related degradation.

The final SER documents the closure of confirmatory items addressing fatigue of Class 1

components. These confirmatory items were closed by the applicant's commitments to perform

additional actions to address fatigue of the auxiliary spray line piping and environmentally assisted

fatigue of the pressurizer surge line, safety injection nozzles, charging nozzles, and residual heat

removal line. These commitments will ensure that the effects of fatigue are appropriately managed.

Reactor vessel head inspections identified flaw indications in two nozzle penetrations of Unit 2.

Weld repairs were performed. No leakage was identified in the reactor vessel head penetrations of

Unit 1. Both reactor vessel heads are scheduled for replacement by 2007. Inspections of bottom5-3
mounted instrumentation nozzles in both units have not identified any leakage, and the applicant

has committed to follow the recommendations the industry is developing for aging management of

Alloy 600 components.

No issues related to the matters described in 10 CFR 54.29(a)(1) and (a)(2) preclude renewal of the

operating licenses for CNP Units 1 and 2. The programs committed to and established by the

applicant provide reasonable assurance that CNP Units 1 and 2 can be operated in accordance with

their current licensing basis for the period of extended operation without undue risk to the health and

safety of the public. The application for renewal of the operating licenses for CNP Units 1 and 2

should be approved.

Sincerely

IRAI

Graham B. Wallis

Chairman

References

1. Indiana Michigan Power Company, "Donald C. Cook Nuclear Plant License Renewal

Application," October 2003

2. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License

Renewal of the Donald C. Cook Nuclear Plant, Units 1 and 2," May 2005

3. U.S. Nuclear Regulatory Commission, 'Safety Evaluation Report with Open Items Related to

the License Renewal of the Donald C. Cook Nuclear Plant, Units 1 and 2," December 2004

4. U.S. Nuclear Regulatory Commission, "Donald C. Cook Nuclear Power Plant, Units 1 and 2

NRC License Renewal Scoping/Screening Inspection Report 05000315/2004003 (DRS);

05000316/2004003 (DRS)," June 22, 2004

5. U.S. Nuclear Regulatory Commission, 'D.C. Cook Nuclear Power Plant, Units 1 and 2 NRC

Aging Management Program Inspection Report No. 05000315/2004013 (DRS);

05000316/2004013 (DRS)," January 10, 2005

6. Information Systems Laboratories, Inc., "Audit and Review Report for Plant Aging

Management Reviews and Programs, Donald C. Cook Nuclear Plant, Units 1 & 2,"

September 22, 2004

5-4
6. CONCLUSION

The staff of the U.S. Nuclear Regulatory Commission (NRC or the Commission) reviewed the

license renewal application for the Donald C. Cook Nuclear Plant, Units 1 and 2, in accordance with

Commission regulations and NUREG-1 800, "Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants," issued July 2001. Title 10, Section 54.29, of the Code of

Federal Regulations (10 CFR 54.29), "Standards for the Issuance of a Renewed License," provides

the standards for the issuance of a renewed license.

On the basis of its evaluation of the license renewal application as discussed above, the NRC staff

has determined that the requirements of 10 CFR 54.29(a) have been met.

The staff notes that the requirements of Subpart A of 10 CFR Part 51 regarding the Donald C. Cook

Nuclear Plant, Units 1 and 2, are documented in Supplement 20 to NUREG-1437, "Generic

Environmental Impact Statement for License Renewal of Nuclear Plants: Regarding Donald C. Cook

Nuclear Plant, Units No. land 2, Final Report," dated May 2005.

6-1
APPENDIX A

COMMITMENTS FOR LICENSE RENEWAL

During the review of the Donald C. Cook Nuclear Plant License Renewal Application by the U. S. Nuclear Regulatory Commission staff,

the applicant made additional commitments to provide aging management programs to manage the aging effects of structures and

components prior to the extended period of operation, as well as other information. The following table lists these commitments, along with

the implementation schedule and the source of the commitment.

ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

1 The Alloy 600 Aging Management Program will be Unit 1: ML033070177 B.1.1

implemented prior to the'period of extended operation. October 25; 2014 10/31/2003

This program will manage aging effects of Alloy 600/690 Attachment 1 See also Item 2

components'and Alloy 52/152 and 82/182'welds in the Unit 2: below for changes in

reactor coolant system that are not addressed by other December 23, 2017 the implementation

aging management programs. This program will detect schedule and Item 3

primary water stress corrosion cracking prior to the loss for additional

of component intended function by using the discussion related to

examination and inspection requirements specified in' this commitment.

American Society of Mechanical Engineers (ASME)

Boiler and Pressure Vessel (B&PV) Code, Section Xl.

2 The Alloy 600 Aging Management Program Unit 1: ML042470410 B.1.1

commitment will also be revised to indicate that an October 25, 2011 08/11/2004

inspection plan will be submitted for staff review and Attachment 2

approval 3 years prior to the period of extended Unit 2: RAI B.1.1.2-1

operation to determine if the program demonstrates an December 23, 2014

ability to manage the effects of aging pursuant to

10 CFR 54.21 (a)(3).

A-.1
COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

I&M will continue to participate in industry initiatives, Unit 1: ML042470410 B.1.1

such as the Westinghouse Owners Group and the October 25, 2011 08/11/2004

Electric Power Research Institution'(EPRI) Materials Attachment 2

reliability Program (MRP). Susceptibility rankings and Unit 2: RAls B.1.1.2-1

program inspection requirements regarding Alloy 82/182 December 23, 2014 and B.1.1.2-3

pipe butt welds will be consistent with the later version

of the EPRI MRP safety assessment or its successors.

4 The Boric Acid Corrosion Prevention Program will be

consistent with the program described in NUREG-1 801,

July 2001, Section Xl.M1 0. The program will be

enhanced to include the attributes documented in LRA,

Section B.1.4, Page B-26.

Unit 1:

October 25, 2014

ML033070177

10/31/2003

Attachment 1

B.1.4

Unit 2:

December 23, 2017

The following enhancements to the Boric Acid Corrosion

Prevention Program will be implemented prior to the

period of extended operation:

* The program scope will be revised to address

electrical components in addition to ferrite steel.

* The program acceptance criteria will be revised to

address electrical components in addition to ferrite

steel.

A-2

a
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

5 The Buried Piping Inspection Program will be Unit 1: ML033070177 B.1.6 implemented prior to the period of extended operation. October 25, 2014 10/31/2003

The program will include (a) preventive measures to Attachment 1

mitigate corrosion, and (b) periodic inspections to Unit 2:

manage the effects of corrosion on the pressure- December 23, 2017

retaining capability of buried carbon steel piping and

tanks. Preventive measures will be in accordance with

standard industry practice for maintaining external

coatings and wrappings. Buried piping and tanks

including buried piping and tanks constructed from

carbon steel and iron that are not within the scope of

license renewal will be inspected when they are

excavated during maintenance. Deficiencies associated

with out-of-scope piping and tanks will be evaluated for

extent of condition, as applicable, to in-scope buried

piping and tanks.

The Buried Piping Inspection Program will be consistent

with, but include an exception to, the program described

in NUREG-1801, July, 2001, Section XI.M34, as

documented in LRA, Section B.1.6. Page B-31.

I A-3
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

6 The Cast Austenitic Stainless Steel (CASS) Evaluation Unit 1: ML033070177 B.1.7

Program will be implemented prior to the period of October 25, 2014 10/31/2003

extended operation. The program will include a Attachment 1

determination of the susceptibility of the CASS Unit 2:

components to thermal aging embrittlement based on December 23, 2017

casting method, molybdenum content, and percent

ferrite. Prior to the period of extended operation, CNP

will develop aging management program details (e.g.,

plans for additional volumetric inspections or flaw

tolerance evaluations) for the reactor coolant system

piping heats of material that are susceptible to reduction

of fracture toughness.

The CASS Evaluation Program will be consistent with

the program described in NUREG-1 801, July 2001,

Section XI.M12, as documented in LRA, Section B.1.7,

Page B-33.

A-4

--- ----
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

7 The Fire Protection Program will be consistent with, but Unit 1: ML033070177 B.1.11.1

include exceptions to, the program described in October 25, 2014 10/31/2003

NUREG-1 801, July 2001, Section XL.M26, as Attachment 1

documented in LRA, Section 6.1.11.1, Pages B-42 to Unit 2:

B-44.- The program will be enhanced to include the December 23, 2017

attributes documented in LRA, Section B.1.11.1,

Pages B-45 and B-46.

The following enhancements to the Fire Protection

Program will be implemented prior to the period of

extended operation:

* In the carbon dioxide (CO2) and halon procedures,

ensure that conditions that may affect the

performance of the system (such as corrosion,

mechanical damage, or damage to dampers) are

observed and degraded conditions are addressed by

means of the Corrective Action Program.

* Enhance procedures to ensure the diesel fuel supply

line is monitored for degradation during performance

testing.

A-5
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

8 The Fire Water System Program will be consistent with, Unit 1: ML033070177 B.1.11.2

but include exceptions to, the program described in October 25, 2014 10/31/2003

NUREG-1801, July 2001, Section XI.M27, as Attachment 1

documented in LRA, Section B.1.11.2, Pages B-47 and Unit 2:

B-48. The program will be enhanced to include the December 23, 2017

attributes documented in LRA, Section B.1.11.2, Page

B-49.

The following enhancements will be implemented prior

to the period of extended operation:

* A sample of sprinkler heads will be inspected using

the guidance of the National Fire Protection Act

(NFPA) document NFPA 25, Section 2.3.3.1.

* The Fire Water System Program will be enhanced to

perform non-intrusive measurement of pipe wall

thickness based on the NRC interim staff guidance 4

(ISG-4). (ADAMS Accession No. ML023440137)

9 The Heat Exchanger Monitoring Program will be Unit 1: ML033070177 B.1.13

implemented prior to the period of extended operation. October 25, 2014 10/31/2003

The program will inspect heat exchangers for Attachment 1

degradation using non-destructive examinations, such Unit 2:

as eddy current inspections or visual inspections, or if December 23, 2017

appropriate, the heat exchanger will be replaced. If

degradation is found, an evaluation will be performed to

determine its effects on the heat exchanger design

functions.

A-6
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

10 The following enhancements to the Inservice Inspection Unit 1: ML033070177 B.1.18

(ISI) - ASME Section Xl, Augmented Inspections October 25, 2014 10/31/2003

Program will be implemented prior to the period of Attachment 1

extended operation: Unit 2:

* An augmented ISI volumetric inspection of the spray December 23, 2017

additive tanks and the portions of the containment

spray system that are wetted by sodium hydroxide.

* An augmented ISI volumetric inspection of the

portions of the discharge header in containment that

may contain water with concentrated contaminants.

11 The. following enhancement to the Instrument Air Quality Unit 1: ML033070177 B.1.19

Program will be implemented prior to the period of October 25, 2014 10/31/2003

extended operation: Attachment 1

* Enhance the CNP Program procedure prior to the Unit 2:

period of extended operation to clearly specify December 23, 2017

frequencies for the dewpoint and dryer tours.

A-7
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

l_ RAI No.

12 The Non-EQ Inaccessible Medium-Voltage Cable Unit 1: ML033070177 B.1.20 Program is a new program that will be implemented October 25, 2014 10/31/2003

prior to the period of extended operation. This program Attachment 1

applies to inaccessible (e.g., in conduit or direct-buried) Unit 2:

medium-voltage cables within the scope of license December 23, 2017

renewal that are exposed to significant moisture

simultaneously with applied voltage. This program will

test these cables 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 consistent with the program described

in NUREG-1 801, July 2001, Section XI.E3, as

documented in LRA Section B.1.20, Page B-71.

A-8
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

13 The Non-EQ Instrumentation Circuits Test Review Unit 1: ML033070177 B.1.21

Program will be implemented prior to the period of October 25, 2014 10/31/2003

extended operation. The electrical cables included in Attachment 1

the scope of this program meet all of the following Unit 2:

criteria: December 23, 2017

* not subject to the EQ requirements of 10 CFR 50.49,

* used in instrumentation circuits with sensitive, highvoltage, low-level signals, and

* exposed to adverse localized environments caused

by heat, radiation, or moisture

This program will be consistent with the program

described in NUREG-1801, Section Xl.E2, with the

exception noted in the LRA Section B.1.21, Pages B-72

and B-73.

A-9 , I
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

14 The Non-EQ Insulated Cables and Connections Unit 1: ML033070177 B.1.22

Program will be implemented prior to the period of October 25, 2014 10/31/2003

extended operation. The Non-EQ Insulated Cables and Attachment 1

Connections Program will apply to accessible insulated Unit 2:

cables and connections installed in structures within the December 23, 2017

scope of license renewal and prone to adverse localized

environments.

The Non-EQ Ihsulated Cables and Connections

Program will be consistent with the program described

in NUREG-1801, July 2001, Section Xl.E1, as

documented in LRA Section B.1.22, Pace B-74.

A-10
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

15 The following enhancements to the Pressurizer Unit 1: ML033070177 B.1.24

Examinations Program will be implemented prior to the October 25, 2014 10/31/2003

period of extended operation: Attachment 1

* The condition of the internal spray head, spray head Unit 2:

locking bar, and coupling will be determined by a December 23, 2017

one-time visual examination (VT-3) of these

conmponents in one CNP unit. This examination will

be performed to accepted ASME Section XI

methods and standards to ensure that degradation

of these items has not occurred.

* If flaws are detected in the spray head, spray head

locking bar, or coupling, engineering analysis will be

completed to determine corrective actions which

could include replacement of the spray head. The

need for subsequent inspections will be determined

after the results of the initial inspection are evaluated.

A-11
e IMPLEMENTATION

SCHEDULE

SOURCE

ADAMS

Accession No.

Document Date

Attachment No.

RAI No.

INFORMATION

LRA Section No.

Comments

I I

16 The Preventive Maintenance Program will be enhanced

to include the attributes documented in LRA Section

B.1.25, Pages B-86 and B-87, and as amended in the

supplemental response to RAI 2.3.3.8-6.

The following enhancements to the Preventive

Maintenance (PM) Program will be implemented prior to

the period of extended operation:

* Revise PM tasks for the emergency diesel generator

(EDG) ventilation system to include inspection of the

flex joints; for the control room ventilation air handler

packages to include inspection of the heat

exchanger tubes and flex joints; and for the auxiliary

feedwater pump room cooling units to include

inspection of the internal evaporator tubes, valves

and tubing.

* The PM program will manage the aging effects for

the emergency diesel engine elastomer flex hoses or

tubing, reactor coolant pump lube oil leakage

collection components, rubber hoses in the

compressed air system, rubber hoses in the

Post-Accident Containment Hydrogen Monitoring

System reagent gas supply, security diesel engine

elastomer flex hoses or tubing, and elastomer

condensate storage tanks floatin_ head seals.

Unit 1:

October 25, 2014

Unit 2:

December 23, 2017

ML033070177

10/31/2003

Attachment 1

B.1.25

See Item 37 for the

amendment to this

commitment provided

in the supplemental

response to RAI

2.3.3.8-6.

I - I _________________________________________ -I.

A-12
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

'_ . RAI No.

17 The Reactor Vessel Integrity Program will be consistent Unit 1: ML033070177 B.1.26

with the program described in NUREG-1 801, July 2001, October 25, 2014 10/31/2003

Section Xl.M31.,,The program will be enhanced to Attachment 1

include the attributes documented in LRA Section Unit 2:

B.1 .26, Page B-89. December 23, 2017

The following enhancements to the Reactor Vessel

Integrity Program will be implemented prior to the

period of extended operation:

* I&M will pull and test one additional standby.

capsule for each unit between 32 effective fullpower years (EFPYs)'and 48 EFPYs to cover the

peak fluence expected at 60 years. A fluence

update will be performed at approximately

32 EFPYs when Capsules W (Unit 1) and S

-(Unit 2) are pulled and tested. A subsequent

fluence update will be performed when the standby

capsules are pulled and tested between 32 EFPYs

and 48 EFPYs.,

* Modifications to design and operation that result in

changes to the neutron energy spectrum or

operating temperatures will be compared to the

original environment in which the capsules were

irradiated. ,

A-13
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

18 The Reactor Vessel Internals Plates, Forgings, Welds, Unit 1: ML042390469 B.1.27

and Bolting Program commitment will be revised to October 25, 2011 08/19/2004

indicate that the program to manage void swelling will Attachment 2 This commitment has

be submitted for staff review and approval 3 years prior Unit 2: RAI B.1.27-2 been superseded by

to the period of extended operation. December 23, 2014 Item 36.

19 The Reactor Vessel Internals Plates, Forgings, Welds, Unit 1: ML033070177 B.1.27

and Bolting Program is a new program that will be October 25, 2014 10/31/2003

implemented prior to the period of extended operation. Attachment 1 See also Item 36

This program will include visual inspections and Unit 2: below for changes in

non-destructive examinations of the reactor vessel December 23, 2017 the implementation

internals during the period of extended operation. A schedule

visual inspection will be performed on plates, forgings,

and welds to detect and monitor cracking caused by

Irradiation Assisted Stress Corrosion Cracking

enhanced by reduction of fracture toughness by

irradiation embrittlement and distortion due to swelling.

For baffle bolts, a volumetric inspection of critical

locations will be performed to assess cracking.

I&M will participate in industry-wide programs designed

by the pressurized water reactor (PWR) Materials

Reliability Project Issues Task Group for investigating

the impacts of aging on PWR vessel internal

components.

A-14
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

20 The Reactor Vessel Internals CASS Program will be Unit 1: ML033070177 B.1.28

implemented prior to the period of extended operation. October 25, 2014 10/31/2003

This program will provide visual inspections and non- Attachment 1

destructive examinations of the reactor vessel internals Unit 2:

during the period of extended operation. The program December 23, 2017

will monitor propagation of cracks from existing flaws.

In addition.to the features of the program described in

NUREG-1 801, Section XI.M13, the program will

manage the aging effect of distortion due to void

swelling'of the reactor vessel internals. Applicable

components will be determined based on the neutron

fluence and thermal embrittlement susceptibility of the

component.

I&M will participate in industry-wide programs designed

by the pressurized water reactor (PWR) Materials

Reliability Project Issues Task Group for investigating

the impacts of aging on PWR vessel internal

components.

I.

.

A-15
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

21 The Service Water System Reliability Program will be Unit 1: ML033070177 B.1.29

consistent with, but include exceptions to, the program October 25, 2014 10/31/2003

described in NUREG-1801, July 2001, Section XI.M20, Attachment 1

as documented in LRA, Section B.1.29, Pages B-95 Unit 2:

and B-96. The program will be enhanced to include the December 23, 2017

attributes documented in LRA Section B.1.29,

Page B-96.

The following enhancements to the Service Water

System Reliability Program will be implemented prior to

the period of extended operation:

* The Service Water System Reliability Program will

be enhanced to check for selective leaching during

visual inspections.

* Develop new PM activity or revise existing PM

activity to ensure the 8-inch expansion joints in the

essential service water supply lines to the EDG heat

exchangers are inspected for evidence of loss of

material, change in material properties, and cracking.

A-16
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

22 The Small Bore Piping Program will be implemented Unit 1: ML033070177 B.1.30

prior to the period of extended operation. The small October 25, 2014 10/31/2003

bore piping inspection will involve a one-time volumetric Attachment 1

examination of susceptible items in selected locations of Unit 2:

Class 1 small bore piping. These inspections will occur December 23, 2017

at or near the end of the initial operating period for CNP

Units 1 and 2.

23 The Structures Monitoring Program will be consistent Unit 1: ML033070177 B.1.32

with the program described in NUREG-1801, July 2001, October 25, 2014 10/31/2003

Section XI.S6. The program will be enhanced to include Attachment 1

the attributes documented in LRA Section B.1.32, Unit 2:

Pages B-101 and B-102. December 23, 2017

.The following enhancements to the Structures

Monitoring Program will be implemented prior to the

period of extended operation:

Include the following in the Structures Monitoring

Program - equipment supports, instrument panels,

racks, cable trays, conduits, cable tray supports,

conduit supports, elastomers, pipe hangers/supports,

fire protection pump house superstructure and walls,

gas bottle storage tank rack and foundation, security

diesel generator room, switchyard control house, fire

protection water storage tank foundation, primary

water storage tank foundation, and the roadway west

of the screenhouse.

A-17
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No. ____ RAI No.

24 The Structures Monitoring - Crane Inspection Program Unit 1: ML033070177 B.1.33

will be consistent with, but include exceptions to, the October 25, 2014 10/31/2003

program described in NUREG-1801, July 2001, Section Attachment 1

XI.M23, as documented in LRA Section B.1.33, Page Unit 2:

B-104. The program will be enhanced to include the December 23, 2017

attributes documented in LRA Section B.1.33, Page B105.

The following enhancements to the Crane Inspection

Program will be implemented prior to the period of

extended operation:

Develop procedures or recurring tasks to (1)

evaluate the effectiveness of the maintenance

monitoring program and the effects of past and

future usage on the structural reliability of in-scope

cranes, (2) verify that in-scope crane rails and

structural components are visually inspected on a

routine basis for loss of material, and (3) verify that

significant visual indications of loss of material due to

corrosion or wear are evaluated according to

applicable industry standards and good industry

practice.

A-18

----
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

25 The Structures Monitoring - Masonry Wall Program will Unit 1: ML033070177 B.1.36

be consistent with the program described in October 25, 2014 10/31/2003

NUREG-1 801, July 2001, Section XI.S5. The program Attachment 1

will be enhanced to include the attributes documented in Unit 2:

LRA Section B.1.36, Page B-1 12. December 23, 2017

The following enhancement to the Masonry Wall

Program will be implemented prior to the period of

extended operationInclude the following in the Masonry Wall Program:

* 4-hour fire-rated masonry block in the turbine

building and screenhouse

* Masonry block in the auxiliary building

Enhancement of the Masonry Wall Program will include

enhancement of the Plant Structures Performance

Evaluation and Monitoring Program procedure to

specify that the following masonry walls are within the

scope of this procedure:

* Masonry Walls in the auxiliary building that perform a

license renewal intended function

* Fire-rated masonry walls in the turbine building and

screenhouse

A-19
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No. __ RAI No.

26 The System Testing Program will be enhanced to Unit 1: ML033070177 B.1.37

include the attributes documented in LRA Section October 25, 2014 10/31/2003

B.1.37, Pages B-1 14 through B-1i18, as clarified below. Attachment 1

Unit 2:

The following enhancements will be implemented prior December 23, 2017

to the period of extended operation:

* Develop a preventive maintenance (PM) procedure

to inspect the centrifugal charging pumps minimum

flow orifices and the Unit 1 centrifugal charging

pumps discharge orifices. The PM will include

ensuring that internal erosion of the orifices would be

detected by inspections.

* Ensure procedures for engineered safety features

ventilation unit, the fuel handling area exhaust unit,

and control room ventilation unit surveillance testing

include visual verification that the drain valves and

drain piping have not experienced loss of material to

the extent that their pressure boundary function is

compromised. The procedures will include

inspection of the external surfaces of ventilation

drain valves and drain piping for any through-wall

degradation (e.g., pinholes, etc.) or any general

corrosion.

A-20

-- .1 -------
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

27 The System Walkdown Program will be enhanced to

include the attributes documented in LRA Section

B.1.38, Page B-121, as clarified below.

The following enhancements will be implemented in

the System Walkdown Program prior to the period of

extended operation to: -

* Ensure that balance of plant (BOP) systems are

adequately addressed with regard to license

renewal considerations. -

* Enhance the program description to emphasize

management expectations that the entire system,

where accessible, is walked down once a refueling

cycle.

* Enhance the program description to emphasize the

accessibility of aspects of the system during

refueling and maintenance outages.

* Ensure that evidence of corrosion is monitored -

adequately. ; !

* Enhance the program description to emphasize the

need to walkdown existing aging concerns, and to

provide feedback to management regarding their

condition (i.e., in system health reports or

Corrective Action Program). If the condition

declines significantly, initiate a condition report for

further evaluation.

Unit 1:

October 25, 2014

ML033070177

10/31/2003

Attachment 1

B.1.38

Unit 2:

December 23, 2017

I I _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

A-21
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

* the impact of non-safety related systems,

structures, and components (SSCs) on safety

related components with emphasis that

preventive measures will be taken prior to loss of

an SSC's license renewal intended function

* extrapolation of conditions found in accessible

structures/components to inaccessible

structures/ components

* ensuring that changes in materiaVenvironment

combinations are addressed. Examples include;

soil or water covering a pipe that was previously

uncovered and excessive moisture in the area

where previously not present

Develop and implement enhanced administrative

controls.

28 The Wall Thinning Monitoring Program is a new Unit 1: ML033070177 B.1.39

program that will be implemented prior to the period of October 25, 2014 10/31/2003

extended operation. The Wall Thinning Monitoring Attachment 1

Program inspections will be performed to ensure piping Unit 2:

wall thickness is above the minimum required in order to December 23, 2017

avoid failures under normal conditions and postulated

transient and accident conditions, including seismic

events. _

A-22
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

l_ RAI No.

29 The Water Chemistry Control - Primary and Secondary Unit 1: ML033070177 B.1.40.1

Water Chemistry Control Program will be consistent October 25, 2014 10/31/2003

with the program described in NUREG-1801, July 2001, Attachment 1

Section XI.M2. The program will be enhanced to Unit 2:

include the attributes documented in LRA Section December 23, 2017

B.1.40.1, Pages B-124 and B-125.

The following enhancements to the Primary and

Secondary Water Chemistry Control Program will be

implemented prior to the period of extended operation:

* Revise the program controlling procedures to require

individual implementing procedures to identify and . prescribe any special collection and preservation

needs of a sample.

* Bring the parameters monitored/inspected and

acceptance criteria into clear alignment with the

EPRI water chemistry guidelines.

* Include sulfate monitoring criteria for the refueling

water storage tank (RWST) that are consistent with

the EPRI guidelines, and the sulfate criteria for other

_systems impacted by RWST chemistry.

I'

A-23
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

30 The Water Chemistry Control - Chemistry One-Time Unit 1: ML033070177 B.1.41 Inspection Program will be implemented and completed October 25, 2014 10/31/2003

prior to the period of extended operation. Combinations Attachment 1 See also Item 39 for of nondestructive examinations (including visual, Unit 2: additional discussion ultrasonic, and surface techniques) will be performed by December 23, 2017 related to this qualified personnel following procedures that are commitment. consistent with the Section Xl of the ASME B&PV Code

and 10 CFR 50, Appendix B. Followup of

unacceptable inspection findings may include expansion of the inspection sample size and locations.

A-24
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

31 The Fatigue Monitoring Program will be consistent with, Unit 1: ML033070177 B.2.2

but include an exception to, the program described in October 25, 2014 10/31/2003

NUREG-1801, July 2001, Section X.M1, as Attachment 1 See also Items 33, documented in LRA Section B.2.2, Page B-133. The Unit 2: 34, and 35 for

program will be enhanced to include the attributes December 23, 2017 additional

documented in LRA, Section B.2.2, Page B-1 34. commitments related

to the Fatigue The following enhancements to the Fatigue Monitoring Monitoring Program. Program will be implemented prior to the period of

extended operation:

I&M will perform one or more of the following prior to the

period of extended operation for the pressurizer surge

line:

* Further refine the fatigue' analysis to lower the

pressurizer surge line cumulative usage factors to

below 1.0.

* Repair the affected locations.

* Replace the affected locations.

* Manage the effects of fatigue of the pressurizer

surge line by an NRC-approved inspection program.

* Review changes to ASME B&PV Code actions

relating to environmental fatigue. Any refined

analysis will use the methodology approved by the

ASME Committee and the NRC.

A-25
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

32 Interim staff guidance (ISG) document, ISG-5, Unit 1: ML033070177 2.1.3

addresses fuse holders that are not part of a larger October 25, 2014 10/31/2003

assembly, but support safety related and nonsafety Attachment 1

related functions in which a failure of a fuse precludes a Unit 2:

safety function from being accomplished. Fuse holders December 23, 2017

that meet these requirements will be evaluated before

the beginning of the period of extended operation for

possible aging effects. The fuses will either be

replaced, modified to remove the aging effects, or a

program will be implemented to manage the aging

effects. The aging management program (if needed) for

fuse holders will consider the aging stressors for the

metallic clips.

A-26
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

33 As a supplement to the Fatigue Monitoring Program Unit 1: ML042740439 B.2.2 and 4.3.3

enhancement committed to in LRA Section B.2.2, I&M October 25, 2014 09/21/2004

will perform one or more of the following activities prior Attachment 2 See also Item 31

to the period of extended operation for the Class 1 Unit 2: RAI 4.3.3-1

charging and safety injection nozzles: December 23, 2017

(1) Perform a plant-specific fatigue analysis of the

Class 1 charging and safety injection nozzles,

which includes environmental effects, to ensure

that cumulative usage factors are below, 1.0.

(2) Manage the effects of fatigue of the Class 1

charging and safety injection nozzles by an

NRC-approved inspection program (e.g., periodic

non-destructive examination of the affected

locations at inspection intervals to be determined

by a method accepted by the NRC). The

inspections, are expected to be able to detect

cracking due to thermal fatigue prior to loss of

function. Replacement or repair will then be

implemented such that the intended function will

be maintained for the period of extended

operation.

(3) Repair portions of the Class 1 charging and safety

injection nozzles at the affected locations, as

necessary to ensure the intended function will be

maintained for the period of extended operation.

A-27
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

(4) Replace portions of the Class 1 charging and

safety injection nozzles at the affected locations,

as necessary to ensure the intended function will

be maintained for the period of extended

operation.

(5) Monitor ASME Code activities to use the

environmental fatigue methodology approved by

the ASME Code Committee and the NRC.

34 I&M will review the piping loads on the remaining hot Unit 1: ML041750561 B.2.2 and 4.6.2

penetrations to establish the base loads for the fatigue October 25, 2014 6/16/04

exemption provisions of ASME Code, Attachment 6

Section 1II, paragraph N-415.1. The penetrations will be Unit 2: RAI 4.6.2-1

grouped based on their duty cycle during normal December 23, 2017

operations, including inservice testing duty. The cycle

loads and stresses will be added to the piping analysis

loads as appropriate, and the resultant loads will be

compared to the fatigue exemption provisions of

ASME Code, Section 1II, paragraph N-415.1. Any

penetration group that does not meet the exemption

provisions will be analyzed for fatigue using the most

limiting penetration to represent the group. This

evaluation will be completed prior to entering the period

of extended operation and will be projected to the end of

the period of extended operation.

A-28
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS - LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

35 As an enhancement to the Fatigue Monitoring Program Unit 1: ML041750561 B.2.2 and 4.3.3

described in LRA Section B.2.2,1 &M will perform one or October 25, 2014 06/16/2004

more of the following activities prior to the period of Attachment 6

extended operation for Class 1 portions of residual heat Unit 2: RAI 4.3.3-1

removal (RHR) piping: December 23, 2017

(1) A pla'nt'specific fatigue analysis of Class 1 portions

of RHR piping, which includes environmental

effects, will be performed to ensure that

cumulative usage factors remain below 1.0.

(2), Repair of the Class 1 portions of RHR piping at the

affected locations.

(3) Replacement of the Class 1 portions of RHR

piping at the affected locations.

(4) Manage the effects of fatigue of the Class 1

portions of RHR piping by an NRC-approved

inspection program (e.g., periodic non-destructive

examination of the affected locations at inspection

intervals to be determined by a method accepted

by-the NRC). The inspections are expected to be

able to detect cracking due to thermal fatigue prior

to loss of function. Replacement or repair will then

be implemented such that the intended function

will be maintained for the period of extended

operation.

(5) Monitor ASME Code activities to use the

environmental fatigue methodology approved by -

A-29
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

36 I&M will submit the Reactor Vessel Internals Plates, Unit 1: ML042960028 B.1.27

Forgings, Welds, and Bolting Program for NRC staff October 25, 2011 10/18/2004

review and approval 3 years prior to the period of Attachment 2

extended operation. Unit 2: RAI B.1.27-2

December 23, 2014

The Reactor Vessel Intemals Plates, Forgings, Welds,

and Bolting Program will be consistent with the program

described in NUREG-1 801, July 2001, Section Xl.M1 6,

as documented in LRA Section B.1.27, Page B-92.

37 The Preventive Maintenance (PM) Program will manage Unit 1: ML042960028 B.1.25 and 2.3.3.8

loss of material for the EDG exhaust silencer internals. October 25, 2014 10/18/2004

Visual inspections of the EDG exhaust silencer Attachment 2

internals will be performed before the period of Unit 2: RAI 2.3.3.8-6

extended operation as part of the PM Program. The December 23, 2017

frequency of future inspections will be based on the

initial inspection results.

38 An insulation resistance test method, such as time- Unit 1: ML042960028 B.1.21 and 3.6

domain reflectometry (TDR), will be continued through October 25, 2014 10/18/2004

the period of extended operation as part of the Non-EQ Attachment 2

Instrumentation Circuits Test Review Program. The test Unit 2: RAI 3.6-2

frequency of instrumentation cables that are in the December 23, 2017

scope of this program, but are disconnected during

calibration, shall be determined by l&M based on

engineering evaluation, but will not be less than once

every 10 years.

A-30
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No. ._ RAI No.

39 I&M will include the auxiliary steam system copper Unit 1: ML042960028 B.1.41 and 3.3.2.1.11

heater coils, cast iron strainer housings, and carbon October 25, 2014 10/18/2004

steel traps exposed to an internal steam environment in Attachment 2

the Chemistry One-Time Inspection Program, which is Unit 2: RAI 3.3.2.1.11-1

described in LRA Section B.1.41. December 23, 2017

I&M will include these 10 CFR 54.4(a)(2) components

(i.e., components in the CONT, DRAIN, PASS, RMS,

RWD, and SD systems that are subject to aging

management review and may be pressurized and

contain raw or untreated water) in the Water Chemistry

Conitrol - Chemistry One-Time Inspection Program.

Loss of material from these components, if any, should

progress slowly. The one-time inspection of these

components will provide assurance that loss of material

is occurring 'at a rate slow enough to ensure that the

intended functions of the components will be maintained

during the period of extended operation. This one-time

inspection will be performed near the end of the current

operating terni.! The visual inspections will identify

indications of loss of material. If loss of material is

identified, an evaluation will be performed to confirm

that the rate is sufficiently slow and that loss of intended

A-31
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

function will not occur during the period of extended

operation. For material and environment combinations

with no evidence of loss of material or with very gradual

loss of material, no further actions will be taken. For

material and environment combinations with loss of

material rates such that loss of intended function could

occur during the period of extended operation,

corrective actions will be taken in accordance with the

Corrective Action Program. Appropriate corrective

actions may consist of component replacement or

additional inspections for components with the material

and environment combination in which the excessive

loss of material is found.

40 The frequency noted on Page, 6-3 of WCAP-14070 for Unit 1: ML042960028 B.2.2 and 4.3.1

valve leakage is assumed to occur for each of the October 25, 2014 10/18/2004

reactor years of operation for the plant. The cycles are Attachment 2

assumed to be for 40 years of operation. Therefore, Unit 2: RAI 4.3.1-1

this frequency is time dependent and constitutes a time- December 23, 2017

limited aging analysis (TLAA).

I&M will perform one or more of the following activities to

address fatigue of the auxiliary spray line piping evaluated

in WCAP-14070:

A-32

I-
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No.

RAI No.

(1) Perform a plant-specific fatigue reanalysis of the

auxiliary spray line piping prior to entering the

period of extended operation to ensure that

cumulative usage factors are below 1.0.

(2) Repair piping at the affected locations.

(3). Replace piping at the affected locations.

(4) Manage the effects of fatigue of the auxiliary spray

program (e.g., periodic non-destructive

examination of the affected locations at inspection

intervals to be determined by a method accepted

by the'NRC). It is expected that the inspections

'will be able to detect cracking due to thermal

fatigue prior to loss of function. Replacement or

repair, if necessary, will then be implemented such

that the intended function will be maintained for the

period of extended operation.

41 As an enhancement to the Service Water Reliability Unit 1: ML050950435 B.1.29

Program described in License Renewal Application October 25, 2014 03/24/2005

Section B.1.29: Attachment 2

Unit 2: RAI B.1.29-1

I&M will enhance the Service Water System Reliability December 23, 2017

Program to manage loss of material due to selective

leaching of susceptible materials by visual inspections

and hardness testing or an equivalent physical test. .

A-33
ITEM COMMITMENT IMPLEMENTATION SOURCE INFORMATION

SCHEDULE

ADAMS LRA Section No.

Accession No. Comments

Document Date

Attachment No. ____ RAI No. _ 42 In response to the ACRS License Renewal Unit 1: ML050950435 B.1.6

Subcommittee comment regarding scheduling of buried October 25, 2014 03/24/2005

piping inspections, I&M commits to enhance the new Attachment 2

Buried Piping Inspection Program to require Unit 2:

performance of an inspection of a sample of buried December 23, 2017

piping included in the scope of this program within ten

years after entering the period of extended operation,

unless an opportunistic inspection of similar

underground piping has occurred within this ten-year

period. Before the end of the tenth year of extended

operation, l&M will perform an engineering evaluation to

determine if sufficient inspections have been conducted

to draw a conclusion regarding the ability of the

underground coatings to protect the underground piping

from degradation. If not, l&M will conduct an inspection

of a sample of buried piping to allow that conclusion to

be reached.

A-34
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 Indiana Michigan Power Company (I&M),

and other correspondence regarding the NRC staff's reviews of the Donald C. Cook Nuclear Plant -

(CNP), Units 1 and 2 (under Docket Numbers 50-315 and 50-316) license renewal application

(LRA).

October 27, 2003

October 31, 2003

November 4, 2003

December 4, 2003

January 14, 2004

January 15,2004

January 15, 2004

March 3, 2004

April 23, 2004

May 6, 2004

May 7, 2004

In a letter (signed by P. Kuo), NRC informed I&M their partial fee waiver for

the process improvements in safety reviews of the D.C. Cook Nuclear Plant,

Units 1 and 2 license renewal application was granted. ML033460291

In a letter, AEP:NRC:3034, (signed by M. K. Nazar), l&M submitted its LRA

for the Donald C. Cook Nuclear Plant, Units 1 and 2. ML033070177

In a letter (signed by P. Kuo), NRC informed l&M of the receipt of the LRA

for CNP Units 1 and 2 and Johnny Eads will be the PM for safety review and

Robert Schaaf will be PM for environmental review. ML033100447

In a letter (signed by P. Kuo), NRC informed I&M the LRA was accepted and

sufficient for docketing and proposed review schedule. ML033381153

In a letter, AEP:NRC:4034, (signed by M. K. Nazar), I&M provided a

response to NRC concerning RAls related to the staffs review of the LRA.

ML040290749

In a memorandum (signed by J. Eads), NRC summarized the September

26, 2003 meeting between the NRC staff and l&M regarding the revised

review process and the LRA. ML040158428

In a memorandum (signed by J. Eads), NRC summarized the November

12, 2003 meeting between the NRC staff and l&M to discuss the LRA.

ML040160457

In a letter (signed by J. Eads), NRC provided l&M a revised schedule for the

conduct of review for CNP. ML040650264

In a letter, AEP:NRC:4034-02, (signed by M. K. Nazar), I&M provided

supplemental information to NRC concerning AMP audits related to the

staff's review of the LRA. ML041270484

In a letter (signed by J. Eads), NRC provided l&M requests for additional

information concerning its review of the LRA. ML041280528

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA.- ML041280509

B-1
May 7, 2004

May 10, 2004

May 10, 2004

May 10, 2004

May 19, 2004

May 20 2004

May 26, 2004

June 1, 2004

June 8, 2004

June 8, 2004

June 16, 2004

June 22, 2004

In a letter, AEP:NRC:4034-01, (signed by M. K. Nazar), I&M provided a

response to NRC concerning RAIs related to the staff's review of the LRA.

ML041390360

In a memorandum (signed by J. Rowley), NRC summarized the

March 25 and 26, 2004 conference call between the NRC staff and l&M

concerning draft RAls concerning the LRA. ML041330551

In a memorandum (signed by J. Rowley), NRC summarized the March 31,

2004 meeting between the NRC staff and l&M concerning scoping and

screening of structures and components used in developing the LRA.

ML041310231

In a memorandum (signed by J. Rowley), NRC summarized the April 13,

2004 meeting between the NRC staff and l&M to discuss proposed

responeses to draft RAls related to the staff's review of the LRA.

ML041310444

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML041400073

In a letter, AEP:NRC:4034-05, (signed by M. K. Nazar), l&M provided a

response to NRC concerning RAls related to the staff's review of the LRA.

ML041550038

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML041480115

In a memorandum (signed by J. Rowley), NRC summarized the May 6, 2004

conference call between the NRC staff and l&M to concerning draft RAls

related to the staff's review of the LRA. ML041530472

In a letter, AEP:NRC:4034-06, (signed by M. K. Nazar), I&M provided a

response to NRC concerning RAls related to the staff's review of the LRA.

ML041680255

In a letter, AEP:NRC:4034-07, (signed by M. K. Nazar), I&M provided a

response to NRC concerning RAls related to the staff's review of the LRA.

ML041670523

In a letter, AEP:NRC:4034-08, (signed by M. K. Nazar), I&M provided a

response to NRC concerning RAls related to the staff's review of the LRA.

ML041750561

In an inspection report, "Donald C. Cook Nuclear Power Plant, Units 1 and 2,

NRC License renewal Scoping/Screening Inspection Report No.

05000315/2004003(DRS); 05000316/2004003(DRS)," NRC summarized the

examination of procedures and records regarding the process of scoping

B-2
and screening plant equipment subject to an aging management review.

ML041740121

June 29, 2004

June 30, 2004

June 30, 2004

June 30, 2004

July 2, 2004

July 26, 2004

July 27, 2004

July 28, 2004

July 30, 2004

August 11, 2004

August 11, 2004

August 11, 2004

In a memorandum (signed by J. Rowley), NRC summarized the

May 12, 2004 conference call between the NRC staff and l&M to concerning

draft RAls related to the staff's review of the LRA. ML041810427

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML041830088

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML041840218

In a letter, AEP:NRC:4034-09, (signed by M. K. Nazar), l&M provided a

response to NRC concerning RAls related to the staff's review of the LRA.

ML041890378

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML041840194

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML042110285

In a memorandum (signed by J. Rowley), NRC summarized the May 17 and

21, 2004 conference call between the NRC staff and l&M to concerning

responses RAls related to the staff's review of the LRA. ML042110275

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML042100372

In a memorandum (signed by J. Rowley), NRC summarized the July 8, 2004

conference call between the NRC staff and l&M to concerning RAls related

to the staff's review of the LRA. ML042120480

In a letter, AEP:NRC:4034-10, (signed by Joseph N. Jensen), I&M provided

a response to NRC concerning RAls related to the staff's review of the LRA.

ML0424704100

In a letter, AEP:NRC:4034-1 1, (signed by Joseph N. Jensen), l&M provided

a response to NRC concerning RAls related to the staff's review of the LRA.

ML042470402

In a letter, AEP:NRC:4034-12, (signed by Joseph N. Jensen), l&M provided

a response to NRC concerning RAls related to the staff's review of the LRA.

ML042450600

B-3
August 19, 2004

August 20, 2004

August 23, 2004

August 31, 2004

September 2, 2004

September 2, 2004

September 3, 2004

September 21, 2004

September 22, 2004

September 22, 2004

September 22, 2004

September 23, 2004

In a letter, AEP:NRC:4034-13, (signed by Joseph N. Jensen), I&M provided

a response to NRC concerning RAIs related to the staff's review of the LRA.

ML042390469

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML042330355

In a memorandum (signed by J. Rowley), NRC summarized the

July 29, 2004 conference call between the NRC staff and l&M to concerning

RAls related to the staff's review of the LRA. ML042370375

In a memorandum (signed by J. Rowley), NRC summarized the

August 10, 2004 conference call between the NRC staff and l&M to

concerning RAls related to the staff's review of the LRA. ML042440671

In a letter (signed by J. Rowley), NRC provided I&M requests for additional

information concerning its review of the LRA. ML042470181

In a letter, AEP:NRC:4034-15, (signed by J. N. Jensen), l&M provided a

response to NRC concerning RAls related to the staff's review of the LRA.

ML042530551

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML042470393

In a letter, AEP:NRC:4034-16, (signed by J. N. Jensen), l&M provided a

supplemental responses to NRC concerning RAls related to the staff's

review of the LRA. ML042740439

In an audit report, "Audit and Review Report for Plant Aging Management

Reviews and Programs - Donald C. Cook Nuclear Plants, Units 1 and 2,"

NRC summarized its audit and review on aging management review and

programs associated with the CNP LRA. ML042880347

In a memorandum (signed by J. Rowley), NRC summarized the

August 24, 2004 conference call between the NRC staff and I&M

concerning follow-up items RAls related to the staff's review of the LRA.

ML042790273

In an audit trip report (signed by D. Thatcher), NRC summarized the

scoping and screening methodology audit regarding the Indiana Michigan

Power Company license renewal application for the Donald C. Cook

Nuclear Plant, Units 1 and 2, dated October 21, 2003. ML042600599

In a memorandum (signed by J. Rowley), NRC summarized the

September 7, 2004 conference call between the NRC staff and l&M

concerning follow-up items to RAls related to the staff's review of the LRA.

ML042790484

B-4
September 24, 2004

September 27, 2004

September 29, 2004

September 29, 2004

October 1, 2004

October 15, 2004

October 15, 2004

October 18, 2004

October 19, 2004

October 28, 2004

November 12, 2004

November 18, 2004

November 26, 2004

In a letter (signed by J. Rowley), NRC provided I&M requests for additional

information concerning its review of the LRA. ML042710130

In an e-mail (from N. Haggerty to J. Rowley), l&M provided a response to

NRC concerning RAls related to the staff's review of the LRA.

ML050560138

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML042730269

In a memorandum (signed by J. Rowley), NRC summarized the

September 1, 2003 meeting between the NRC staff and l&M to discuss the

LRA. ML042740562

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML042750313

In a memorandum (signed by J. Rowley), NRC summarized the September

8, 2004 conference call between the NRC-staff and l&M to discuss and

clarify an RAI related to the staff's review of the LRA. ML042920161

In a memorandum (signed by J. Rowley), NRC summarized the September

16, 2004 conference call between the NRC staff and l&M to discuss and

clarify an RAI related to the staff's review of the LRA. ML042920437

In a letter, AEP:NRC:4034-17, (signed by J. N. Jensen), l&M provided a

response to NRC concerning RAls related to the staff's review of the LRA..

ML042960028

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML042930422

In a letter, AEP:NRC:4034-19, (signed by J. N. Jensen), l&M provided the

annual update information. ML043090467

In a memorandum (signed by J. Rowley), NRC summarized the

October 13, 2004 conference call between the NRC staff and l&M to

discuss and clarify an RAI related to the staff's review of the LRA.

ML043170667

In a letter, AEP:NRC:4034-20, (signed by J. N. Jensen), l&M provided the

annual update information. ML042960028

In a memorandum (signed by J. Rowley), NRC summarized the

October 27, 2004 conference call between the NRC staff and l&M to

discuss and clarify RAls related to the staff's review of the LRA.

ML043360131

B-5
December 21, 2004

December 23, 2004

January 10, 2005

January 12, 2005

January 12, 2005

January 21, 2005

February 11, 2005

February 17, 2005

February 25, 2005

March 2, 2005

March 10, 2005

In a report, "Safety Evaluation Report with Open Items Related to the

License Renewal of the Donald C. Cook Nuclear Plant, Units 1 and 2," NRC

documents its technical review of the CNP LRA. ML043570539

In a memorandum (signed by J. Rowley), NRC summarized the

November 10, 2004 conference call between the NRC staff and l&M to

discuss and clarify RAls related to the staff's review of the LRA.

ML043650004

In an inspection report, "Donald C. Cook Nuclear Power Plant, Units 1 and

2, NRC Aging Management Program Inspection Report No.

0500315/2004013(DRS); 05000316/2004013(DRS)," NRC summarized the

examination of procedures and records regarding implementation of aging

management programs to support license renewal. ML050100227

In a memorandum (signed by J. Rowley), NRC summarized the

November 23, 2004 conference call between the NRC staff and l&M to

discuss and clarify RAls related to the staff's review of the LRA.

ML050120443

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML050120254

In a letter, AEP:NRC:5034, (signed by J. N. Jensen), l&M provided the

responses to Open and Confirmatory Items in the Safety Evaluation Report

with Open Items related to the License Renewal of Donald C. Cook Nuclear

Plant, Units 1 and 2. ML050330373

In a memorandum (signed by J. Rowley), NRC summarized the

January 11, 2005 conference call between the NRC staff and I&M to

discuss and clarify RAls related to the staff's review of the LRA.

ML050460139

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML050490312

In a letter (signed by J. Rowley), NRC provided l&M requests for additional

information concerning its review of the LRA. ML050560152

In a letter, AEP:NRC:5034-01, (signed by D. P. Fadel), l&M provided

comments on the Safety Evaluation Report with Open Items related to the

License Renewal of Donald C. Cook Nuclear Plant, Units 1 and 2.

ML050690328

In a memorandum (signed by J. Rowley), NRC summarized the

March 1, 2005 conference call between the NRC staff and l&M concerning

comments made by Advisory Committee on Reactor Safeguards during the

subcommittee meeting on the CNP LRA. ML050690376

B-6
March 24, 2005

May 29, 2005

June 28, 2005

July 13, 2005

July 18, 2005

In a letter, AEP:NRC:5034-02, (signed by J. N. Jensen), l&M provided

response to request for additional information and Advisory Committee on

Reactor Safeguards license renewal subcommittee comment.

ML050950435

In a report, "Safety Evaluation Report Related to the License Renewal of the

Donald C. Cook Nuclear Plant, Units 1 and 2," NRC documents its final

technical review of the CNP LRA. ML051510015

In a memorandum (signed by J. Rowley), NRC summarized the

June 22, 2005 conference call between the NRC staff and l&M to discuss

and clarify issues related to the staff's review of the LRA. ML051800335

In a memorandum (signed by J. Rowley), NRC summarized the

July 1, 2005 conference call between the NRC staff and l&M to discuss and

clarify issues related to the staff's review of the LRA. ML051940523

In a letter (signed by G. Wallis), the Advisory Committee on Reactor

Safeguards provided its conclusions and recommendations on the renewal

of the operating license for Donald C. Cook Nuclear Plant, Units 1 and 2.

ML052000080

B-7
APPENDIX C: 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 Donald C. Cook Nuclear

Plant, Units 1 and 2, Docket Numbers 50-315 and 50-316.

American Society of Mechanical Engineers (ASME)

ASME Code, Section III

ASME Code, Section III, Class 1

ASME Code, Section 1II, Classes 2 and 3

ASME Code, Section 1II, Subsection NC-3200

ASME Code, Section Vil, Division 1

ASME Code, Section VilI, Division 2

ASME Code, Section Vil, Division 1; AWWA; or MSS

ASME Code, Sections Vil or IlIl, Subsections NC or ND

ASME Code, Section Xl

ASME Code, Section Xl, Subsection IWL

ASME Code Appendix G to Section Xl

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 El 85-82, "Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels"

ASTM E-185, "Standard Practice for Conducting Surveillance Tests for Light Water Cooled Nuclear

Power Vessels"

ASTM standard D 1796, Standard Test Method for Water and Sediment in Fuel Oils by the

Centrifuge Method (Laboratory Procedure), 2002

C-1
I

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

C-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

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-105714, 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

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 10CFR 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

C-3
I I

NRC Bulletin 2001-01, "Circumferential Cracking of Reactor Pressure Vessel Head Penetration

Nozzles," August 3, 2001

NRC Bulletin 2002-01, "Reactor 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

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

C-4
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, "Inservice 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, "Completion 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 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

NUREG-1801, "Generic Aging Lessons Learned (GALL) Report, U.S. Nuclear Regulatory

Commission," April 2001

NUREG-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)

C-c
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-104, 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

Westinghouse Topical Reports (WCAP)

WCAP-15973-P, "Low-Alloy Steel Component Corrosion Analysis Supporting Small-Diameter Alloy

600/690 Nozzle Repair/Replacement Programs"

C-6
APPENDIX D: PRINCIPAL CONTRIBUTORS

Name

Pao-Tsin Kuo

Samson Lee

Jonathan Rowley

Johnny Eads

Thelma Davis

Yvonne Edmonds

Melissa Jenkins

Gregory Suber

Juan Ayala

Veronica Rodriguez

Frank Akstulewicz

Hansraj Ashar

Jose Calvo

Terence Chan

Stephanie Coffin

Gregory Cranston

Robert Dennig

Kevin Coyne

James Downs

Naeem Iqbal

Laura Kozak

Jacob Zimmerman

Greg Galletti

Chia-fu Sheng

Hanry Wagage

Thomas Cheng

Gene Imbro

Ronaldo Jenkins

Om Chopra

Eric Reichelt

James Strnisha

Gregory Makar

Raul Hemandez

Renee (Yueh-U) Li

Tilda Liu

Louise Lund

Jai Rajan

Kamal Manoly

Richard McNally

Patricia Loughheed

Edwin Forrest

James Pulsipher

David Solorio

David Terao

RESPONSIBILITY

Branch Chief

Section Chief

Project Manager

Project Manager

Clerical Support

Administrative Support

Administrative Support

Project Manager

Technical Support

Technical Support

Branch Chief

Civil Engineering

Branch Chief

Section Chief

Section Chief

Team Leader

Section Chief

Quality Assurance

Fire Protection

Fire Protection

Regional Inspector

Project Manager

Quality Assurrance

Materials Engineering

Plant Systems

Civil Engineering

Branch Chief

Section Chief

Electrical Engineering

Materials Engineering

Mechanical Engineering

Materials Engineering

Plant Systems

Mechanical Engineering

Project Management

Section Chief

Civil Engineering

Section Chief

Mechanical Engineering

Inspection Team Leader

Safety Assessment

Safety Assessment

Section Chief

Section Chief

D-1
Dale Thatcher

Muhammad Razzaque

Steve West

Sunil Weerakkody

John Hannon

Jared Wermiel

William Bateman

Steve Jones

Theodore Quay

John Fair

Pei-Ying Chen

Section Chief

Reactor Systems

Section Chief

Section Chief

Section Chief

Branch Chief

Branch Chief

Plant Systems

Branch Chief

Mechanical Engineering

Mechanical Engineering

Contractors

Information Systems Laboratories, Inc.

Brookhaven National Laboratory

Pacific Northwest National Laboratories

D-2
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, It any.)

BIBLIOGRAPHIC DATA SHEET

(See instnictrons on the reverse) NUREG-1831

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Safety Evaluation Report Related to the License Renewal of the Donald C. Cook Nuclear Plant, MONTH YEAR

Units 1 and 2

July 2005

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Jonathan G. Rowley

7. PERIOD COVERED (inclusive Dates)

10/31/2003 - 05/29/2005

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (IfNRC. provide Division. OticeorRegon. US. NuclearRegulatoryCommissin. andmailingaddress;ffcontractor,

provide narne and madiwg address.)

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, D.C. 20555-001

9. SPONSORING ORGANIZATION -NAME AND ADDRESS rattn. "ye 'Same as above'; contractor, provide NRCDvsion, OfficeorRegon, U.S. NucfearRegulatotyCommwo.

and mailirn address.)

Same as item number 8 above

10. SUPPLEMENTARY NOTES

Docket No. 50-315 and No. 50-316

11. ABSTRACT (200 words or less)

This safety evaluation report (SER) documents the technical review of the Donald C. Cook Nuclear Plant (CNP), Units 1 and

2, license renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated

October 31, 2003, Indiana Michigan Power Company (the applicant) submitted the LRA for CNP in accordance with Title 10,

Part54, 'Requirements for Renewal of Operating Ucenses for Nuclear Power Plants,' of the Code of Federal Regulations (10

CFR Part 54 or the Rule). The applicant is requesting renewal of the operating license for CNP Unit 1 (LicenseNo. DRP-58) and

CNP Unit 2(LicenseNo. DRP-74) for a period of 20 years beyond the current license expirations of midnight, October25, 2014

and December 23, 2017, respectively.

The CNP is located along the eastern shore of Lake Michigan in Lake Charter Township, Berrien County, Michigan;

approximately 11 miles south southwest of Benton Harbor, Michigan. The nearest town is Bridgman, Michigan, which is

approximately 2 miles south of the plant site. Each unit employs a pressurized water reactor (PWR) nuclear steam supply

system (NSSS) fumished by Westinghouse Electric Corporation. The Unit 1 reactor is licensed for a power output of 3304

megawatts-thermal (MWt), and the Unit 2 reactor is licensed for a power output of 3468 MWt. The approximate net electrical

outputs of Unit 1 and Unit 2 are 1080 megawatts-electric (MWe) and 1155 MWe, respectively.

The staff reviewed the CNP license renewal application 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. The staff's

conclusion of its review of the CNP LRA can be found in Section 6 of this SER.

12. KEY WORDS/DESCRIPTORS (List words orphrases that will assist researchers n locating the report.) 13. AVAJLASIJTY STATEMENT

10 CFR Part 54, license renewal application, Donald C. Cook Nuclear Power Plant, scoping, unlimited

screening, aging management, time-limited aging analysis, safety evaluation report, Docket No. 14. SECURITY CLASSIFICATION

50-315, Docket No. 50-316, operating license number DPR-58, operating license number DPR-74, (This Page)

Indiana Michigan Power Company unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (9-2004) PRINTED ON RECYCLED PAPER
Federal Recycling Program

I I
UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

OFFICIAL BUSINESS