NUREG-1 825

Safety Evaluation Report

Related to the License Renewal of

the Joseph M. Farley Nuclear Plant,

Units 1 and 2

Docket Nos. 50-348 and 50-364

Southern Nuclear Operating Company, Inc.

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Washington, DC 20555-0001
3

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NUREG-1825

Safety Evaluation Report

Related to the License Renewal of

the Joseph M. Farley Nuclear Plant,

Units 1 and 2

Docket Nos. 50-348 and 50-364

Southern Nuclear Operating Company, Inc.

Manuscript Completed: May 2005

Date Published: May 2005

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
ABSTRACT

This safety evaluation report (SER) documents the technical review of the Joseph M. Farley

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

Nuclear Regulatory Commission (NRC) (the staff). By letter dated September 12, 2003,

Southern Nuclear Operating Company, Inc. (SNC or the applicant) submitted the LRA for FNP

in accordance with Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54). The

SNC is requesting renewal of the operating licenses for FNP, Units 1 and 2 (Facility Operating

License Numbers NPF-2 and NPF-8, respectively) for a period of 20 years beyond the current

expiration dates of midnight, June 25, 2017, for Unit 1 and midnight, March 31, 2021, for Unit 2.

The FNP units are located about 16.5 miles east of the City of Dothan, in Houston County,

Alabama, on the west bank of the Chattahoochee River. The NRC issued the construction

permits for FNP, Units 1 and 2, on August 16, 1972. The operating licenses were issued by the

NRC on June 25, 1977, for Unit 1 and March 31, 1981, for Unit 2. The FNP consists of two

Westinghouse pressurized-water reactor units. Each unit is designed to generate 2775

megawatt thermal (MWt), or approximately 910 megawatt electric (MWe).

The staff reviewed the FNP 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 FNP LRA can be found in Section 6 of this SER.

Since its issuance, the SER has been revised to clarify a license condition listed in Section 1,

Introduction and General Discussion, under Subsection 1.7, Summary of Proposed License

Conditions. The revision is identified by a status bar in the right margin.

The NRC license renewal project manager is Ms. Tilda Liu. Ms. Liu may be reached

at (301) 415-1315. Written correspondence should be addressed to the License Renewal and

Environmental Impacts Program, Mail Stop 0-11 F1, U.S. Nuclear Regulatory Commission,

Washington, DC 20555-0001.

iii
TABLE OF CONTENTS

ABSTRACT ......................................

TABLE OF CONTENTS ................ , .....

ABBREVIATIONS ..................................

. iii

V.

xix 

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

1.1 Introduction ............... .......... ' 1.2 License Renewal Background ... ...................................

1.2.1 Safety Review .................... ' . .

1.2.2 Environmental Review ..................................... 1.3 Principal Review Matters .................... ' 1.4 Interim Staff Guidance .................... ;.

1.5 Summary of Open Items ............................................

1.6 Summary of Confirmatory Items ,.....;..............................

1.7 Su nmary of Proposed License Conditions ............................

2. STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

................................. ...............................

2.1 Scoping and Screening Methodology.

2.1.1 Introduction ........................................ '

1-1

1-1

1-2

1-3

1-4

1-5

1-6

1-8

1-8

1-8

2-1

2-1

2-1

, i

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

2.1.2.1 Scoping Methodology .2-2

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

....2-2

2.1.2.1.2 Docurrientation Sources Used for Scoping and

Screening '....... 2-4

2.1.2.1.3 Plant- and System-Level Scoping ..... ......... 2-4

2.1.2.1.4 Component-Level Scoping ....... ............ 2-5

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

2.1.2.2.1 Mechanical Component Screening ..... ........ 2-6

2.1.2.2.2 Structural Corrponent Screening ..... ......... 2-6

2.1.2.2.3 Electrical/I&C Component Screening ..... ...... 2-7

2.1.3 Staff Evaluation .2-7

2.1.3.1 Scoping ............... 2-8

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

......................................... 2-10

2.1.3.1.2 Plant-Level Scoping of Systems and Structures

Ii.: ... . % .2-17

2.1.3.1.3 Component-Level Scoping ......... .......... 2-17

2.1.3.2 Screening Methodology ................... 2-21

2.1.3.2.1 Mechanica Component Screening .2-21

2.1:3.2.2 Structural Component Screening ..... ........ 2-22

2.1.3.2.3 Electrical andl&C Component Screening .2-23

2.1.4 Conclusion ............. 2-25

V
II

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

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

2.2.2 Summary of Technical Information in the Application .... ......... 2-25

2.2.3 Staff Evaluation .................. ....................... 2-27

2.2.4 Conclusion .......................... 2-37

2.3 System Scoping and Screening Results-Mechanical Systems .... ........ 2-37

2.3.1 Reactor Vessel Internals and Reactor Coolant System .... ....... 2-38

2.3.1.1 ReactorVessel .................................. 2-39

2.3.1.1.1 Summary of Technical Information in the Application

........... ............................... 2-39

2.3.1.1.2 Staff Evaluation ........................... 2-39

2.3.1.1.3 Conclusion ......... ..................... 2-40

2.3.1.2 Reactor Vessel Internals ........ .................... 2-40

2.3.1.2.1 Summary of Technical Information in the Application

......................................... 2-40

2.3.1.2.2 Staff Evaluation ........................... 2-41

2.3.1.2.3 Conclusion ......... ..................... 2-42

2.3.1.3 Reactor Coolant System and Connected Lines .... ...... 2-42

2.3.1.3.1 Summary of Technical Information in the Application

..... ............................. 2-42

2.3.1.3.2 Staff Evaluation ....... .................... 2-44

2.3.1.3.3 Conclusion ......... ..................... 2-45

2.3.1.4 Steam Generators .......... ...................... 2-45

2.3.1.4.1 Summary of Technical Information in the Application

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

2.3.1.4.2 Staff Evaluation ........................... 2-46

2.3.1.4.3 Conclusion .............................. 2-46

2.3.2 Engineered Safety Features ........ ....................... 2-46

2.3.2.1 Containment Spray System ...... ................... 2-47

2.3.2.1.1 Summary of Technical Information in the Application

..... ............................. 2-47

2.3.2.1.2 Staff Evaluation ........................... 2-48

2.3.2.1.3 Conclusion ......... ..................... 2-48

2.3.2.2 Containment Isolation System ...... ................. 2-49

2.3.2.2.1 Summary of Technical Information in the Application

. ..... ................................ 2-49

2.3.2.2.2 Staff Evaluation ........................... 2-50

2.3.2.2.3 Conclusion ........ ...................... 2-50

2.3.2.3 Emergency Core Cooling System ...... .............. 2-51

2.3.2.3.1 Summary of Technical Information in the Application

. ....... ................................ 2-51

2.3.2.3.2 Staff Evaluation ........................... 2-52

2.3.2.3.3 Conclusion ....... ....................... 2-53

2.3.3 Auxiliary Systems .................. ...................... 2-53

2.3.3.1 New Fuel Storage ............... .................. 2-53

2.3.3.1.1 Summary of Technical Information in the Application

.................... 2-53

2.3.3.1.2 Staff Evaluation .............................. 2-54

vi
2.3.3.1.3 Conclusion ................. 2-54

-2.3.3.2 Spent Fuel Storage I-. ;' ........................ ;.'.2-54

2.3.3.2.1 Summary of Technical Information in the Application ............... 2-54

2'3.3.2.2 Staff Evaluation .................. 2-55

2.3.3.2.3 Conclusion ................. 2-57

2.3.3.3 Spent Fuel Pool Co6ling and Cleanup System ..... ..... 2-57

2.3.3.3.1 Summary of.Technical Information in the Application ......... .... 2-57

2.3.3.3.2 Staff Evaluation .................. 2-57

2.3.3.3.3 Conclusion ...... ............ 2-59

2.3.3.4 Overhead Heavy'and Refueling Load Handling System ... 2-59

2.3.3.4.1 Summary of Technical Information in the Application

....... . .. . ................. 2-59

2.3.3.4.2 Staff Evaluation' .. .... 2-59

2.3.3.4.3 Conclusion .............................. 2-61

2.3.3.5 Open-Cycle Cooling'Water System ................... 2-62

2.3.3.5.1 Summary of Technical Information in the Application ................ 2-62 -.2.3.3.5.2 Staff Evaluation ........................... 2-63

2.3.3.5.3 Conclusion ............................ 2-64

2.3.3.6 Closed-Cycle Cooling Water System .................. 2-65

2.3.3.6.1 Summary of Technical Information in the Application

................ 2-65

2.3.3.6.2 Staff Ea to2-65....................... 2.3.3.6.3 Conclusion .2-69

2.3.3.7 Compressed Air System .2-69

2.3.3.7.1 Summary of Technical Information in the Application . . 2-69

2.3.3.7.2 Staff Evaluation ........................... 2-70

2.3.3.7.3 Conclusion .............................. 2-75

2.3.3.8 Chemical and Volume Control System ...... .......... 2-75

2.3.3.8.1 Summary of Technical Information in the Application ....2-75

2.3.3.8.2 -Staff Evaluation .2-76

2.3.3.8.3 Conclusion .2-76

2.3.3.9 Control Room Area Ventilation System ...... .......... 2-77

2.3.3.9.1 Summary of Technical Information in the Application ........ ............... 2-77

-2.3.3.9.2 Staff Evaluation. .................... 2-77

2.3.3.9.3 Conclusion ......................... 2-78

2.3.3.10 Auxiliary and Radwaste Area Ventilation System .2-78

2.3.3.10.1 Summary of Technical Information in the Application .... 2-78 -~~~~~ . . . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... ; 27 '2.3.3.10.2'Staff Evaluation .......................... 2-79

2.3.3.10.3 Conclusion . 2-80

2.3.3.11 Primary Containmrent Ventilation System .2-80

2.3.3.11.1 Summary of Technical lnformation in the Application . 2-80

vii
11

2.3.3.11.2 Staff Evaluation .......................... 2-81

2.3.3.11.3 Conclusion ........ ..................... 2-82

2.3.3.12 Yard Structures Ventilation System ..... ............. 2-82

2.3.3.12.1 Summary of Technical Information in the Application

......................................... 2-82

2.3.3.12.2 Staff Evaluation .......................... 2-83

2.3.3.12.3 Conclusion ........ ..................... 2-83

2.3.3.13 Fire Protection .......... ........................ 2-84

2.3.3.13.1 Summary of Technical Information in the Application

................................ 2-84

2.3.3.13.2 Staff Evaluation .......................... 2-84

2.3.3.13.3 Conclusion ........ ..................... 2-88

2.3.3.14 Diesel Fuel Oil System ....... .................... 2-89

2.3.3.14.1 Summary of Technical Information in the Application

......................................... 2-89

2.3.3.14.2 Staff Evaluation .......................... 2-89

2.3.3.14.3 Conclusion ........ ..................... 2-92

2.3.3.15 Emergency Diesel Generator System ..... ........... 2-93

2.3.3.15.1 Summary of Technical Information in the Application

......... ............................... 2-93

2.3.3.15.2 Staff Evaluation .......................... 2-93

2.3.3.15.3 Conclusion ....... ..................... 2-101

2.3.3.16 Demineralized Water System ...... ............... 2-101

2.3.3.16.1 Summary of Technical Information in the Application

........................................ 2-101

2.3.3.16.2 Staff Evaluation ....... .................. 2-102

2.3.3.16.3 Conclusion ........ .................... 2-104

2.3.3.17 High-Energy Line Break Detection System .... ....... 2-104

2.3.3.17.1 Summary of Technical Information in the Application

......................................... 2-104

2.3.3.17.2 Staff Evaluation ......................... 2-105

2.3.3.17.3 Conclusion ........................... 2-106

2.3.3.18 Hydrogen Control System ........................ 2-107

2.3.3.18.1 Summary of Technical Information in the Application

....................................... 2-107

2.3.3.18.2 Staff Evaluation ........................ 2-108

2.3.3.18.3 Conclusion ........................ 2-108

2.3.3.19 Liquid Waste and Drains ........................ 2-108

2.3.3.19.1 Summary of Technical Information in the Application

........................................ 2-108

2.3.3.19.2 Staff Evaluation ......................... 2-111

2.3.3.19.3 Conclusion ........ .................... 2-117

2.3.3.20 Oil-Static Cable Pressurization System ..... ......... 2-117

2.3.3.20.1 Summary of Technical Information in the Application

........................................ 2-117

2.3.3.20.2 Staff Evaluation ....... .................. 2-118

2.3.3.20.3 Conclusion ........ .................... 2-120

2.3.3.21 Potable and Sanitary Water System ..... ........... 2-120

viii
2.3.3.21.1 Summary of Technical Information in the Application

............ 2-120

2.3.3.21.2'Staff Evaluation . ......................... . 2-121

2.3.3.21.3 Conclusion .2-122

2.3.3.22 Radiation Monitoring System .2-122

2.3.3.22.1 Summary of Technical Information in the Application

.. 2-122

2.3.3.22.2 Staff Evaluation .2-123

2.3.3.22.3 Conclusion ............... 2-124

2.3.3.23 Reactor Makeup Water Storage System .'.2-125

2.3.3.23.1 Summary of Technical Information in the Application . . .... .. ................ 2-125

2.3.3.23.2 Staff Evaluation .2-125

2.3.3.23.3 'Cnclusion . 2-130

2.3.3.24 Sampling System ... 2-130

2.3.3.24.1 Summary of Technical Information in the Application

........................................ 2-130

2.3.3.24.2 Staff Evaluatin .2-131

2.3.3.24.3 Conclusion ............... '. .. 2-132

2.3.4 Steam and Power Conversion Systems.. 2-132

2.3.4.1 Main Steam System . . .2-133

2.3.4.1.1 Summarybf Technical Information in the Application

................ '2-133

2.3.4.1.2 Staff Evaluation .. 2-133

2.3.4.1.3 Conclusion . .2-135

2.3.4.2 Feedwater System-....... ...................... 2-136

2.3.4.2.1 Summary'of Technical Information in the Application .. 2-136

2.3.4.2.2 Staff Evaluation .. 2-137

2.3.4.2.3 Conclusion . .2-138

2.3.4.3 Steam Generator Blow'down System.2-138

2.3.4.3.1 Summary of Technical Information in the Application ...... 2-138

2.3.4.3.2 Staff Evaluation .. 2-139

2.3.4.3.3 Conclusion .. 2-140

2.3.4.4 Auxiliary Feedwater System .......... ... 2-140

'' 2.3.4.4.1 Sumrimary of Technical Information in the Application

.. 2-141

2.3.4.4.2 Staff Evaluation .. 2-141

2.3.4.4.3 Conclusion ............ .2-143 .

2.3.4.5 Auxiliary Steam and Condensate Recovery System . 2-144

2.3.4.5.1 Summary of Technical Information in the Application

......... 2-144

2.3.4.5.2 -Staff Evaluation. - 2-144

2.3.4 5.3 Conclusion .: :. .. .-. .; -.... 2-147

2.3.4.6 Turbine and Turbine Auxiliaries .2-147

2.3.4.6.1 Summary of Technical Information in the Application ................................. 2-147

ix
1I

2.3.4.6.2 Staff Evaluation .................. 2-148

2.3.4.6.3 Conclusion ...... ............ 2-149

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

Supports .............. .... 2-150

2.4.0 Staff Evaluation .. 2-151

2.4.1 Containment Structures .. 2-155

2.4.1.1 Summary of Technical Information in the Application .... 2-155

2.4.1.2 Staff Evaluation .. 2-156

2.4.1.3 Conclusion .. 2-161

2.4.2 Other Structures .. 2-161

2.4.2.1 Auxiliary Building .. 2-161

2.4.2.1.1 Summary of Technical Information in the Application

. ....................................... 2-161

2.4.2.1.2 Staff Evaluation .. 2-162

2.4.2.2 Diesel Generator Building .. 2-162

2.4.2.2.1 Summary of Technical Information in the Application . ....................................... 2-162

2.4.2.2.2 Staff Evaluation .. 2-163

2.4.2.3 Turbine Building .. 2-163

2.4.2.3.1 Summary of Technical Information in the Application . ....................................... 2-163

2.4.2.3.2 Staff Evaluation .. 2-164

2.4.2.4 Utility Piping Tunnels .. 2-164

2.4.2.4.1 Summary of Technical Information in the Application . ....................................... 2-164

2.4.2.4.2 Staff Evaluation .. 2-164

2.4.2.5 Water Control Structures .. 2-165

2.4.2.5.1 Summary of Technical Information in the Application

. ....................................... 2-165

2.4.2.5.2 Staff Evaluation .. 2-165

2.4.2.6 Steel Tank Structures (Foundations and Retaining Walls) ......... .................................... 2-167

2.4.2.6.1 Summary of Technical Information in the Application . ....................................... 2-167

2.4.2.6.2 Staff Evaluation .. 2-167

2.4.2.7 Yard Structures .. 2-168

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

2.4.2.7.2 Staff Evaluation .. 2-168

2.4.2.8 Conclusion .. 2-170

2.4.3 Component Supports .. 2-170

2.4.3.1 Summary of Technical Information in the Application .... 2-170

2.4.3.2 Staff Evaluation .. 2-171

2.4.3.3 Conclusion .. 2-172

2.5 Scoping and Screening Results-Electrical and Instrumentation and Controls

Systems................................................... 2-172

2.5.1 Summary of Technical Information in the Application .. 2-173

2.5.2 Staff Evaluation ........................................ 2-174

x
2.5.3 Conclusion .................................... 2-177

2.6 Conclusion for Scoping and Screening ... 2-177

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

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

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

3.0.1.1 Overview of Table . 3-2

-3.0.1.2 Overview of Table2 ........................ 3-3

3.0.2 The Staffs Review Process ........................ 3-4

-3.0.2.1 Review of AMPs . 3-4

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

3.0.3 Aging Management Programs .3-6

3.0.3.1 AMPs That Are Consistent with the GALL Report .3-8

3.0.3.1.1 Borated Water Leakage Assessment and Evaluation

Program ....... 3-10

3.0.3.1.2 Steam Generator Program .3-16

3.0.3.1.3 Summary of Conclusion for AMPs That Are Consistent

with the GALL Report . ............... 3-20

3.0.3.2 AMPs That Are Consistent with the GALL Report, but with

Exceptions and/or Enhancements ......... . 3-20

3.0.3.2.1 -Water Chemistry Control Program .3-21

3.0.3.2.2 Reactor Vessel Surveillance Program ..... ..... 3-23

3.0.3.2.3 Fuel Oil Chemistry Control Program ...... . 3-31

, 3.0.3.2.4 -. Structural Monitoring Program .............. . 3-33

-- ,-. 3.0.3.2.'5 Service Wa'ter-Program .......................... 3-34* 

3.0.3.2.6 Fire Protection Program .................. 3-36

3.0.3.2.7.Reactor'Vessel Intemals Program 3-39

-3.0.3.2.8 Non-EQ Electrical Cables Used in Instrumentation

Circuits ........... . 3-47 .- 3.0.3.2.9 Flow-Accelerated Corrosion ...... ........... 3-50

3.0.3.2.10 Buried Piping and Tank Inspection Program .... 3-52

3.0.3.2.11 Sumrmary of Conclusion for AMPs That Are Consistent

with the GALL Report, but with Exceptions and/or - -, , , . . Enhance-ments ... .............. 3-55

3.0.3.3 AMPs That Are Plant-Specific ................... . 3-55

3.0.3.3.1 Flux Detectorfhimble Inspection Program .. . 3-55

,3.0.3.3.2 External Surfaces Monitoring Program .... ..... 3-65

3.0.3.3.3 NiCrFe Component Assessment Program.3-68

3.0.3.3.4 Periodic Surveillance and Preventive Maintenance

Activities Program ............... ' ... 3-73 , 3.0.3.3.5. Conclusion ................. 3-80

- 3.0.4 Quality Assur'ance Program Attributes Integral to Aging Management

Programs ..... ............ ' 3-80

3.0.4.1 SummaryofTechhical1formationiinApplication .... .... 3-81

-3.0.4.2 Staff Evaluation-... .............................. 3-82 , 3.0.4.3 Conclusion. ................ ,.:':.'.3-83

3.1 -Aging Management of Reactor. ssel, Internals, and Reactor Coolant System .......................... 3-83

xi
- ~~AL

3.1.1 Summary of Technical Information in the Application .... ......... 3-83

3.1.2 Staff Evaluation ............ ............................. 3-84

3.1.2.1 AMR Results That Are Consistent with the GALL Report . . 3-90

3.1.2.1.1 Crack Initiation and Growth Due to Cyclic Loading,

and/or Stress-Corrosion Cracking and Primary Water

Stress-Corrosion Cracking ....... ............. 3-91

3.1.2.1.2 Loss of Fracture Toughness Due to Thermal aging

Embritttlement .............................. 3-92

3.1.2.1.3 Loss of Fracture Toughness Due to Thermal Aging,

Irradiation Embrittlement, and Void Swelling ....... 3-93

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

Which Further Evaluation Is Recommended ..... ........ 3-93

3.1.2.2.1 Cumulative Fatigue Damage ..... ............ 3-94

3.1.2.2.2 Loss of Material Due to Pitting and Crevice Corrosion

......................................... 3-94

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation

Embrittlement ..... ........................ 3-96

3.1.2.2.4 Crack Initiation and Growth Due to Thermal and

Mechanical Loading or Stress-Corrosion Cracking .. 3-98

3.1.2.2.5 Crack Growth Due to Cyclic Loading ..... ...... 3-99

3.1.2.2.6 Changes in Dimension Due to Void Swelling .... 3-99

3.1.2.2.7 Crack Initiation and Growth Due to Stress-Corrosion

Cracking or Primary Water Stress-Corrosion Cracking

........................................ 3-100

3.1.2.2.8 Crack Initiation and Growth Due to Stress-Corrosion

Cracking or Irradiation-Assisted Stress-Corrosion Cracking

........ .r................................ 3-102

3.1.2.2.9 Loss of Preload Due to Stress Relaxation ...... 3-103

3.1.2.2.10 Loss of Section Thickness Due to Erosion .... 3-104

3.1.2.2.11 Crack Initiation and Growth Due to PWSCC, ODSCC,

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 Plates ....... ............. 3-104

3.1.2.2.12 Loss of Section Thickness Due to Flow-Accelerated

Corrosion ............ ..................... 3-105

3.1.2.2.13 Ligament Cracking Due to Corrosion .... .... 3-106

3.1.2.2.14 Loss of Material Due to Flow-Accelerated Corrosion

(PWR) ................................... 3-106

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

the GALL Report .............. ................... 3-107

3.1.2.3.1 Reactor Vessel Aging Management Review Results

.... ................................... 3-107

3.1.2.3.2 Reactor Vessel Internals Aging Management Review

Results ..... ............... 3-118

3.1.2.3.3 Reactor Coolant System and Connected Lines Aging

Management Review Results ...... ........... 3-125

3.1.2.3.4 Steam Generators Aging Management Review Results

........................................ 3-133

xii
3.1.3 Conclusion .... 3-141

3.2 Aging Management of Engineered Safety Features Systems . .3-141

3.2.1 Summary of Technical Information in the Application .3-141

3.2.2 Staff Evaluation ............... :3-142

'3.2.2.1 AMR Results Th'atAre-Consistent with the GALL Report, for

Which Further Evaluation Is Not Recommended .3-144

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

Which Further Evaluation Is Recommended . .3-145

3.2.2.2.1 Cumulative Fatigue Damage .3-146

3.2.2.2.2 Loss of Material Due to General Corrosion . 3-146

3.2.2.2.3 Local Loss of Material Due to Pitting and Crevice

Corrosion ... . ............................ 3-147

3.2.2.2.4 Local Loss of Material Due to Microbiologically

Influenced Corrosion . ............... 3-147

3.2.2.2.5 Changeslin Material Properties Due to Elastomer

Degradation.. . .3-148

3.2.2.2.6 Local Loss of Material Due to Erosion .. 3-148

3.2.2.2.7 Buildup of Deposits Due to Corrosion .. 3-149

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

the GALL Report

'... 3-149

3.2.2.3.1 Containment Spray System AMR Results ...... 3-149

3.2.2.3.2 -Containment Isolation System AMR Results .... 3-151

3.2.2.3.3 Emergency Core Cooling System AMR Results . 3-153

3.2.2.3.4 Generic Issues for the Engineered Safety Features

........................................ 3-157

'3.2.3 -Conclusion ........... .3-160

3.3 Aging Management of Auxiliary Systems .. 3-160

3.3.1 Summary of Technical Information in the Application .3-160

3.3.2 Staff Evaluation ............... 3-161 ;. 

:'3.3.2.1 AMR Results That Are Consistent with the GALL Report, for

Which Further Evaluation Is Not Recommended . 3-166

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

Which Further Evaluation Is Recommended .3-170

3.3.2.2.1 Loss of Material Due to General, Pitting, and Crevice

Corrosion .... '.~.3-171

3.3.2.2.2 Hardening and Cracking or Loss of Strength Due to - Elasto'rer Degradation or Loss of Material Due to Wear - ...... i 3-171

3.3.2.2.3 Cumulative Fatigue Damage ..... ........... 3-172

3.3.2.2.4 Crack Initiation and Growth due to Cracking or Stress-

-Corrosion Cracking '

. .3-172

3.3.2.2.5 Loss of Material Due to General, Microbiologically Influenced, Pitting, and Crevice Corrosion .... .... 3-173

3.3.2.2.6 Loss of Material Due'to General, Galvanic, Pitting, and

Crevice Corrosion' ........... : 3-174

3.3.2.2.7- Loss of Material Due to General, Pitting, Crevice, and

Xiii
Microbiologically Influenced Corrosion and Biofouling

. ....................................... 3-175

3.3.2.2.8 Quality Assurance for Aging Management of NonsafetyRelated Components ......... ............... 3-176

3.3.2.2.9 Crack Initiation and Growth Due to Stress-Corrosion

Cracking and Cyclic Loading ...... ............ 3-176

3.3.2.2.10 Reduction of Neutron-Absorbing Capacity and Loss of

Material Due to General Corrosion ..... ........ 3-177

3.3.2.2.11 Loss of Material Due to General, Pitting, Crevice, and

Microbiologically Influenced Corrosion ..... ..... 3-177

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

the GALL Report ................................. 3-178

3.3.2.3.0 General RAls on AMR Issues ..... .......... 3-178

3.3.2.3.1 New Fuel Storage AMR Results ..... ........ 3-200

3.3.2.3.2 Spent Fuel Storage AMR Results ..... ....... 3-201

3.3.2.3.3 Spent Fuel Pool Cooling and Cleanup AMR Review

. ....................................... 3-202

3.3.2.3.4 Overhead Heavy and Refueling Load Handling System

AMR Review .............................. 3-204

3.3.2.3.5 Open-Cycle Cooling Water System .... ...... 3-204

3.3.2.3.6 Closed-Cycle Cooling Water System .... .... 3-209

3.3.2.3.7 Compressed Air System ...... ............ 3-211

3.3.2.3.8 Chemical and Volume Control System ....... 3-214

3.3.2.3.9 Control Room Area Ventilation System ....... 3-218

3.3.2.3.10 Auxiliary and Radwaste Area Ventilation System

. ....................................... 3-222

3.3.2.3.11 Primary Containment Ventilation System ..... 3-225

3.3.2.3.12 Yard Structures Ventilation System .... ..... 3-228

3.3.2.3.13 Fire Protection ........ .................. 3-230

3.3.2.3.14 Diesel Fuel Oil System ...... ............. 3-232

3.3.2.3.15 Emergency Diesel Generator System ....... 3-236

3.3.2.3.16 Demineralized Water System ..... ........ 3-244

3.3.2.3.17 High-Energy Line Break Detection System ... 3-246

3.3.2.3.18 Hydrogen Control System ..... ........... 3-248

3.3.2.3.19 Liquid Waste and Drains .................. 3-250

3.3.2.3.20 Oil-Static Cable Pressurization System ...... 3-254

3.3.2.3.21 Potable and Sanitary Water System .... ..... 3-256

3.3.2.3.22 Radiation Monitoring System ..... ......... 3-259

3.3.2.3.23 Reactor Makeup Water Storage System ...... 3-260

3.3.2.3.24 Sampling System ....................... 3-264

3.3.3 Conclusion ........ ................. 3-267

3.4 Aging Management of Steam and Power Conversion Systems ........... 3-267

3.4.1 Summary of Technical Information in the Application ............ 3-267

3.4.2 Staff Evaluation .................. ...................... 3-268

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

Which Further Evaluation Is Not Recommended .... .... 3-271

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

Which Further Evaluation Is Recommended ..... ....... 3-272

xiv

11
3.4.2.2.1 Cumulative Fatigue Damage ................ 3-272

-3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice

Corrosion. ......... 3-272

3.4.2.2.3 Loss of Material Due to General, Pitting, and Crevice

Corrosion, Microbiologically Influenced Corrosion, and

. Biofouling % . ..... ; 3-273

3.4.2.2.4 General Corrosion ................... 3-274

3.4.2.2.5. Loss of Material Due to General, Pitting, Crevice, and

-Microbiologically Influenced Corrosion .3-274

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

the GALL Report ;-............ ;3-276

3.4.2.3.1 Main Steam System AMR Results ..... ...... 3-276

3.4.2.3.2 Feedwater System AMR:Results ............. 3-279

3.4.2.3.3 Steam Generator Blowdown System AMR Review

. ...................... .................. 3-281

3.4.2.3.4 Auxiliary Feedwater System AMR Review ...... 3-283

3.4.2.3.5 Auxiliary Steam and Condensate Recovery Syktem

AMR Review. ....... 3-286

3.4.2.3.6 Generic Issues for the Steam and Power Conversion

Systems .... 3-289

.3.4.3 Conclusion...... ......- .... 3-289

3.5 Aging Management of Containments, Structures, and Component Supports

.. 3-290

3.5.1 Summary of Technical Information in the Application ..... ....... 3-290

3.5.2 Staff Evaluation .......-....-- -- : - .;;.-.3-290

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

Which Further Evaluation Is Not Recommended .... .... 3-296

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

Which Further Evaluation Is Recommended .... ........ 3-298

3.5.2.2.1 Aging of Inaccessible Concrete Areas .... .... 3-299

3.5.2.2.2 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 Structural Monitoring

Program .3..... ;.- 3,302

3.5.2.2.3 Reduction of Strength and Modulus of Concrete

Structures Due to Elevated Temperature .. 3-303

3.5.2.2.4 Loss of Material Due to Corrosion in Inaccessible Areas

-of Steel Containment Shell or Liner Plate .. 3-305

3.5.2.2.5 Loss of Prestress Due to Relaxation, Shrinkage, Creep,

and Elevated Temperature ........................ 3-306

3.5.2.2.6 Cumulative Fatigue Damage

.................. 3-306

3.5.2.2.7 Cracking Due to Cyclic Loading and SCC . 3-306

3.5.2.2.8 Aging of Structures Not Covered.by Structural

Monitoring Program,. ....... 3-307

3.5.2.2.9 Aging Management of Inaccessible Areas . 3-308

3.5.2.2.10 Aging of Supports Not Covered by Structural

xv
- LI

Monitoring Program ....... .................. 3-308

3.5.2.2.11 Cumulative Fatigue Damage ..... .......... 3-309

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

the GALL Report ................................. 3-310

3.5.2.3.1 PWR Concrete Containments AMR Results .... 3-310

3.5.2.3.2 Auxiliary Building AMR Results .... .......... 3-314

3.5.2.3.3 Diesel Generator Building AMR Results ....... 3-320

3.5.2.3.4 Turbine Building AMR Results .... .......... 3-322

3.5.2.3.5 Utility/Piping Tunnels AMR Results .... ....... 3-323

3.5.2.3.6 Water Control Structures AMR Results .... .... 3-324

3.5.2.3.7 Steel Tank Structures (Foundations and Retaining

Walls) AMR Results ............ ............ 3-325

3.5.2.3.8 Yard Structures AMR Results .... ........... 3-326

3.5.2.3.9 Component Supports AMR Results .... ....... 3-327

3.5.3 Conclusion .......................... 3-330

3.6 Aging Management of Electrical Components ........... ... .......... 3-330

3.6.1 Summary of Technical Information in the Application ............ 3-330

3.6.2 Staff Evaluation .................. ...................... 3-331

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

Which Further Evaluation Is Not Recommended .... .... 3-334

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

Which Further Evaluation Is Recommended .... ........ 3-335

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

the GALL Report .......... ....................... 3-335

3.6.2.3.1 Electrical Connectors Not Subject to 10 CFR 50.49 EQ

Requirements That Are Exposed to Borated Water

Leakage ....................... .......... 3-336

3.6.2.3.2 Fuse Holders ............................ 3-337

3.6.2.3.3 High-Voltage Insulators .................... 3-339

3.6.2.3.4 Metal-Enclosed Cable Bus .... ............. 3-340

3.6.2.3.5 Oil-Static Cable .......................... 3-344

3.6.2.3.6 Switchyard Bus .......................... 3-346

3.6.2.3.7 Transmission Conductors .... .............. 3-347

3.6.3 Conclusion .......................... 3-349

3.7 Conclusion for Aging Management . . .............. 3-349

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 ........................... 4-2

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

4.2.1 Neutron Fluence ......................................... 4-3

4.2.1.1 Summary of Technical Information in the Application ...... 4-3

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

4.2.1.3 FSAR Supplement ................................. 4-5

4.2.1.4 Conclusion ....................................... 4-6

4.2.2 Upper-Shelf Energy ............... .. ...................... 4-6

xvi
4.2.2.1 Summary of Technical Information in the Application ...... 4-6

4.2.2.2 Stff Evaluation ................ .......- 4-7

4.2.2.3 FSAR Supplement'. .-..... ........... 4-8

4.2.2.4 Conclusion .. 4-8

4.2.3 Pressurized Thermal Shock . ................. ...... 4-8'. 

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

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

4.2.3.3 FSAR Supplement .. .................. 4-10

4.2.3.4 Conclusion ............. - .. 4-11

4.2.4 Adjusted Reference Temperature ........... ............ 4-11

4.2.4.1 Summary of Technical Information in the Application ..... 4-11

4.2.4.2 Staff Evaluation ....... ........ 4-11

4.2.4.3 FSAR Supplement ................... 4-12

4.2.4.4 Conclusion .. 4-13

4.2.5 Pressure-Temperature (P-T) Limits ... .... 4-13

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

4.2.5.2 Staff Evaluation A:..4-14

4.2.5.3 FSAR Supplement ................. 4-14

4.2.5.4 Conclusion ....................... 4-15

4.3 Metal Fatigue ....... . . . 4-15

4.3.1 Fatigue of ASME Class 1 'Components ..... . . 4-15

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

4.3.1.2 Staff Evaluation ...............................-.... 4-16

4.3.1.3 FSAR Supplement ................. 4-20

4.3.1.4 Conclusion........................................ 4-21

4.3.2 Fatigue of the Reactor Coolant Pump Flywheel ...... ........... 4-21

4.3.2.1 Summary of Technical Information in the Application .....- 4-21

4.3.2.2 Staff Evaluation ........... ....................... 4-22

4.3.2.3 FSAR Supplement ................... '4-23

4.3.2.4 Conclusion .................. 4-23

4.3.3 Fatigue of ASME Non-Class I Components ......................... -4-24

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

4.3.3.2 Staff Evaluation .......................... 4-24

4.3.3.3 FSAR Supplement .................. ........ 4-25

4.3.3.4 Conclusion ........................... 4-25

4.3.4 Containment Tendon Prestress ........... ...... 4-25

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

4.3.4.2 Staff Evaluation ......... ......................... 4-25

4.3.4.4 Conclusion ...................................... 4-29

4.3.5 Fatigue of Reactor Vessel Supports .......................... 4-29

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

4.3.5.2 Staff Evaluation .................................. 4-29

4.3.5.3 FSAR Supplement ........ ........................ 4-29

4.3.5.4 Conclusion ...................................... 4-30

4.4 Environmental Qualification of Electrical Equipment ......... ... ......... 4-30

4.4.1 Summary of Technical Information in the Application .... ......... 4-30

4.4.2 Staff Evaluation .................. ....................... 4-31

4.4.3 FSAR Supplement . ' ........................ 4-31

xvii
. -________A L

4.4.4 Conclusion ........................... 4-31

4.5 Other Plant Specific Analyses ....................... .............. 4-31

4.5.1 Ultimate Heat Sink Silting .................................. 4-32

4.5.1.1 Summary of Technical Information in the Application ..... 4-32

4.5.1.2 Staff Evaluation .................................. 4-32

4.5.1.3 FSAR Supplement ................................ 4-34

4.5.1.4 Conclusion ...................................... 4-34

4.5.2 Leak-Before-Break Analysis .................... 4-34

4.5.2.1 Summary of Technical Information in the Application ..... 4-34

4.5.2.2 Staff Evaluation .................................. 4-36

4.5.2.3 FSAR Supplement ................................ 4-38

4.5.2.4 Conclusion ...................................... 4-38

4.5.3 Residual Heat Removal Relief Valve Capacity Verification Calculations

. .................................................... 4-38

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

4.5.3.2 Staff Evaluation .................................. 4-39

4.5.3.3 FSAR Supplement ................................ 4-39

4.5.3.4 Conclusion ...................................... 4-39

4.6 Conclusion for Time-Limited Aging Analyses ......... .. ............... 4-39

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

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

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

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

APPENDIX C: REQUESTS FOR ADDITIONAL INFORMATION ........ ............. C-1

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

APPENDIX E: REFERENCES ............................................... E-1

xviii

AI
ABBREVIATIONS

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

AFW auxiliary feedwater

AISC American Institute of Steel Construction

AMP aging management program,

AMR aging management review

AMSAC ATWS mitigating system actuation circuitry

APC Alabama Power Company,

ART adjusted reference temperature

AS&CR auxiliary steam and condensate recovery

ASME American Society of Mechanical Engineers.

ASTM American Society for Testing and Materials'-

ATWS anticipated transient without scram

BTRS boron thermal regeneration system

BWR boiling-water reactor

CASS cast austenitic stainless steel

CCW closed cooling water or component cooling water

CET core exit thermocouple

CF chemistry factor

CFR Code of Federal Regulations

CLB current licensing basis

CR condition report

CRDM control rod drive mechanism

CRGT control rod guide tube

CS containment spray

CST condensate storage tank

CUF cumulative usage factor

CVCS chemical and volume co'ntrolsystem '

DBA design-basis accident.

DBE design-basis event

DW demineralized water .

ECCS emergency core cooling system

EDG emergency diesel 'generator.

EFPY effective full-power year

EOL end of life

EPRI Electric Power Research Institute

EQ environmental qualification'

ESF engineered safety~feature

FAC flow-accelerated corrosion"

Fen environmental fatigue factors -

FNP Farley Nuclear Plant"' -

FP fire protection

FPP fire protection plan

FSAR final safety analysis report

FSD functional system description

xix
._ IL

FW feedwater

GALL generic aging lessons learned

GDC general design criteria or general design criterion

GEIS generic environmental impact statement

GSI generic safety issue

HAZ heat-affected zone

HELB high-energy line break

HE/ME high energy/moderate energy

HJTC heated junction thermocouple

HVAC heating, ventilation, and air conditioning

HX heat exchanger

l&C instrumentation and control

IEEE Institute of Electrical and Electronics Engineers

IGA intergranular attack

IN information notice

IPA integrated plant assessment

ISG interim staff guidance

IS inservice inspection

LBB leak before break

LOCA loss-of-coolant accident

LOSP loss of offsite power

LRA license renewal application

MWe megawatt electric

MWt megawatt thermal

NEI Nuclear Energy Institute

NEPA National Environmental Policy Act of 1969

NPAR nuclear plant aging research

NRC U.S. Nuclear Regulatory Commission

NSR nonsafety related

NSSS nuclear steam supply system

ODSCC outside-diameter stress-corrosion cracking

OBE operating-basis earthquake

P&ID piping and instrumentation diagram

PRF penetration room filtration

PSRF nonsafety related that can prevent a safety-related function

PTLR pressure-temperature limits report

PTS pressurized thermal shock

PVC polyvinyl chloride

PW pipe whip

PWR pressurized-water reactor

PWSCC primary water stress-corrosion cracking

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

RI-ISI risk-informed inservice inspection

xx
RMWST reactor makeup water storage tank

RPV reactor pressure vessel

RTNDT reference temperature nil ductility transition

RTPTs reference temperature pressurized thermal shock

RTS reactor trip system

RVLIS reactor vessel level instrumentation system

RWST refueling water storage tank

SBO station blackout

SC structure and component

SCC stress-corrosion cracking

SER safety evaluation report

SFP spent fuel pool

SGBD steam generator blowdown

Si safety injection

SMP structural monitoring program

SNC Southern Nuclear Operating Company, Inc.

SR safety related

SRP Standard Review Plan

SRP-LR standard review plan-license renewal

SSC system, structure, and component

SSE safe-shutdown earthquake

SW service water

SWIS service water intake structure

TLAA time-limited aging analysis

TPNS total plant numbering system

TS technical specification

TSP trisodium phosphate

UFSAR updated final safety analysis report

USE upper-shelf energy

WCAP Westinghouse Commercial Atomic Power (report)

WOG Westinghouse Owners Group

xxi
1. INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction -

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

Joseph M. Farley Nuclear Plant (FNP), Units 1arid 2, as filed by the SouthernNuclear

Operating Company, Inc. (SNC.or the applicant). By letter dated September 12, 2003, SNC

submitted its application to the U.S. Nuclear Regulatory Commission (NRC or the Commission)

for renewal of the FNP operating licenses for an additional 20 years. The NRC staff (the staff)

prepared this report, which summarizes the results of its safety review of the renewal

applicatioh for compliance with the requirements of Title 10, Part 54, of the Code of Federal

Regulations, (10 CFR Part 54),;"Requirements'for Renewal of Operating Licenses for Nuclear

Power Plants." The NRC license renewal project manager for the FNP license renewal review

is Ms. Tilda Liu. Ms. Liu can be contacted by telephone at 301-415-1315 or electronic mail at

tyll @nrc.aov. Alternatively, written correspondence may be sent to the following address:

License Renewal and Environmental impacts Program

-U.S. Nuclear Regulatory Commission

Washington, D.C. 20555-0001

Attention: Tilda Liu, Mail Stop 0-11 F1

In its September 12, 2003, submittal letter, the applicant requested renewal of the operating

licenses issued under Section 103 of the Atomic En'ergy Act of 1954, as amiended, for FNP,

Units 1 and 2 (Facility Operating License Nudmbers NPF-2 and NPF-8, respectively), for a

period of 20 years beyond the current license expiration dates of -midnight, June 25, 2017,' for

Unit 1 and midnight, March 31, 2021, f6r Unit 2. The FNP units are located about 16.5 miles'

east of the City of Dothan, in Houston County, 'Alabama, on the west bank of the

Chattahoochee River. The NRC issued the construction permits for FNP, Units 1 and 2, on

August 16, 1972. The NRC issued the operating licenses on June 25, 1977, for Unit 1 and

March 31, 1981, for Unit 2. The FNP consists of two Westinrgh6use pressurized-water reactor

units. Each unit is designed to generate 2775 megawatt thermal (MWt), or approximately 910

megawatt electric (MWe). The final safety analysis report (FSAR) contains details concerning

the plant and the site.' -''

The license renewal process consists of two concurrent reviews-a technical review of safety

issues and an environmental reviewV. The6NRC'regidlationsfound in 10 CFR Parts 54 and 51,'-

respectively, state the requirements for these reviews. The safety review for the FNP license

renewal is based on the applicant's license renewal application (LRA) and on the responses to

the staff's requests for additi6nal informati6o (RAIs). The applicant provided supplemental

information to its LRA as well as responses to the staff's RAls and other'docketed

correspondence. Unless otherwise n6ted, the staff reviewed and considered information

submitted through Septermber 15, 2004. The "staff reviewed information 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 inforrmation. The public rday'review the LRA and all pertinent information and

materials, including the FSAR mentioned above, at the NRC Public Document Room; located in

One White Flint North, 11555 Rockville Pike (first floor), Rockville, Maryland, 20852-2738 (301 - 415-4737/800-397-4209), and at the Houston L-ve''Memoirial Library, 212 West Bdrdeshaw -

1-1
Street, Dothan, Alabama 36303-4421. In addition, the public may find the FNP, Units 1 and 2,

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

www.nrc.aov.

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

technical details considered in evaluating the safety aspects of its proposed operation 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-1 800,

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

(SRP-LR), dated July 2001.

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

issues that it has considered during the review 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 is a table that identifies the applicant's commitments associated with

the renewal of the operating licenses. Appendix B provides a chronology of the principal

correspondence between the NRC and the applicant related to the review of the application.

Appendix C presents an index of the staff's RAls and the applicant's responses. Appendix D is

a list of principal contributors to this SER. Appendix E is a bibliography of the references used

during the course of the review.

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

Generic Environmental Impact Statement (GEIS). This supplement discusses the

environmental considerations related to renewing the licenses for FNP, Units 1 and 2. The

NRC staff issued NUREG-1 437, "Generic Environmental Impact Statement for License

Renewal of Nuclear Plants, Supplement 18: Regarding Joseph M. Farley Plant, Units 1 and 2,

Draft Report for Comment," on August 6, 2004.

1.2 License Renewal Background

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

licenses for commercial power reactors are issued for 40 years. 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, rather than on 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 anticipated interest in license renewal and held a workshop on nuclear power

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

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

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

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

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

procedural issues related to license renewal for nuclear power plants.

In 1991, the NRC published the license renewal rule in 10 CFR Part 54 (the Rule). The NRC

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

and to gain experience necessary to develop implementation guidaiine. 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 arid are managed during the period of initial license. In addition, the NRC found that the -

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

implementation of the Maintenance Rule, which also manages certain 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 NRC initiated these rule changes to ensure that important

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

during the period of extended operation. In addition, the revised rule clarified and simplified the

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

long-lived structures and components (SCs). -

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

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

and to fulfill, in part, 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 principals:

(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 SSCs during

the period of extended operation, as well as 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 thesbetwo principles, 10 CFR'54.4 defines the scope of license renewal as

those SSCs (1) that are safety related,'(2)'wh6se 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 (PTS), anticipated

transients without scram (ATWS), and station blackout (SBO).

Pursuant to 1 0 CFR 54.21 (a), an applicant for a renewed license must review all SSCs that are

withini th6 scope of the Rule to identify SCs that are subject to an aging management review

(AMR). Those'SCs that are'subject to an AMR perform an intended function.without moving

parts, or without a change in configuration'or properties, and are not subject to replacement

based on qualified life or specified time period. As required by 10 CFR 54.21 (a), an applicant - for a renewed license must demonstrate that the effects of aging will be managed in such a way

that the intended function or functions of those'SCs will be maintained, consistent with the

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- - a_

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 effects of aging that may affect active equipment are more readily detectable

and will be identified and corrected through routine surveillance, performance monitoring, and

maintenance activities. The surveillance and maintenance programs for active equipment, as

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

throughout the period of extended operation.

Pursuant to 10 CFR 54.21 (d), each LRA is required to include a supplement to the Final Safety

Analysis Report (FSAR). This FSAR Supplement must contain a summary description of the

applicant's programs and activities for managing the effects of aging and the evaluation of timelimited aging analyses for the period of extended operation.

License renewal also requires the identification and updating of 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

a number 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 the effects of

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

In 2001, the NRC developed and issued Regulatory Guide (RG) 1.188, "Standard Format and

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

endorses NEI 95-10, "Industry Guideline for Implementing the Requirements of

10 CFR Part 54-The License Renewal Rule," which was issued in March 2001 by the Nuclear

Energy Institute (NEI). NEI 95-10 details an acceptable method of implementing the license

renewal rule. The NRC also used the SRP-LR to review this application.

SNC utilizes the process defined in NUREG-1801, "Generic Aging Lessons Learned (GALL)

Report," issued in July 2001. The GALL Report provides the staff with a summary of staffapproved aging management programs (AMPs) for the aging of many SCs that are subject to

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

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

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

summarizes the aging management evaluations, programs, and activities credited for managing

aging for most of the SCs used throughout the industry. The report also serves as a reference

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

has determined will provide adequate aging management during the period of extended

operation.

1.2.2 Environmental Review

Title 10, Part 51, of the Code of Federal Regulations governs the environmental protection

regulations. In December 1996, the staff revised the environmental protection regulations to

facilitate the environmental review for license renewal. The staff prepared a "Generic

Environmental Impact Statement (GEIS) for License Renewal of Nuclear Plants" (NUREG1437, Revision 1) to document its evaluation of the possible environmental impacts associated

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

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GEIS establishes generic findings that are applicabl eto all nuclear power plants. Appendix B to

Subpart A of 10 CFR Part 51 identifies these generic findings. Pursuant to

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

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

must include analyses of those environmental impacts that must be evaluated on a plant-'

specific basis (i.e.,' Category 2 issues).

In accordance with NEPA and the requiremenhts of 10 CFR Part 51, the NRC performed a plantspecific review of the environmental impacts of license renewal, including whether new and

significant information existed that the GEIS did not consider. As part of its scoping process,

the NRC held a public meeting on January 8, 2004,Ain Dothan, Alabama, to identify

environrmental issues specific to the plant. The' NRC's draft plant-specific Supplement 18 to the

FNP, Units 1 and 2, GES, which was issued on August 6, 2004, documents the results of the

environmental review and includes a preliffiinary recommendation with respect to the license

renewal action. The NRC held another public meeting on September 30, 2004, in Dothan,

Alabama, to discuss the 'draft plant-specific Supplement 18 to the FNP, Units 1 and 2, GEIS.

After considering comments on the draft,'the NRC jrepared and published a final plaht-specific

supplement to the GEIS separately from this report. Supplement 18 to NUREG-1437, "Generic

Environmental Impact Statemrmnt for License Renewal of Nuclear Plants: Regarding Joseph M.

Farley Nuclear Plant, Units'1 'and 2, Final Report," was published on March 9, 2005.

1.3 Principal Review Matters

Title 10, Part 54, of the Code of Federal Regulations describes the requirements for renewing

operating licenses for nuclear power plants. The staff performed its technical review of the FNP

LRA in accordance with Commission guidance and the requirements of 10 CFR Part 54.

Title 10, Section'54.29 of the Code of Federal Regulations includes the standards for renewing

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

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

information. The applicant provided this general information in Section 1 of its LRA for FNP,

Units 1 and 2, which was'submitted to the NRC by letter dated September 12, 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 54.19(b), the-Commission requires 'that LRAs include "conforming changes to the

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

of the proposed renewed license." The applicant stated the following in its LRA regarding this

issue: - '

The originral Indemnity Agreement for FNP, which was effective as of July 20, 1976, provides that such

agreement "shall terminate at the time of the'expiration of that license specified in Item 3 of the Attachment,

which is the last to expire." The license originally listed in Item 3 of the Attachment was SNM-1 647. Since

July20, 1976, however, the Indemnity Agreement has'been amended in order to add license numbers

NFP-2, SNM-1 868, and NPF-8 to Item 3 of the-Attachment. As a consequence of these amendments, the

existing Indemnity Agreement is presently due to terminate at midnight, March 21, 2021, as the last of these

licenses expires. SNC requests that conforming changes be made to Item 3 of the Attachment to the

Indemnity Agreement (and any other applicable provisions of the Indemnity Agreement and/or the

attachment) in order to make clear that the Indemnity Agreement Is extended until the last expiration date of

the renewed FNP operating licenses issued by the Commission in response to this application.

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 - :L

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

licenses. Therefore, conforming changes to the indemnity agreement do not need to be made,

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

In 10 CFR 54.21, the Commission requires that each LRA for a renewed license of a nuclear

facility must contain (a) an IPA, (b) a description of any CLB changes that occurred during staff

review of the LRA, (c) an evaluation of TLAAs, and (d) a FSAR Supplement. Sections 3 and 4

and Appendix B to the LRA address the license renewal requirements of 10 CFR 54.21 (a), (b),

and (c). Appendix A to the LRA contains the license renewal requirements of 10 CFR 54.21 (d).

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

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

submit an amendment to the renewal application that identifies any changes to the CLB of the

facility that materially affect the contents of the LRA, including the FSAR Supplement. The

applicant submitted an update to the LRA by letter dated July 20, 2004, which summarized the

changes to the CLB that have occurred at FNP, Units 1 and 2, during the staff's review of the

LRA. This submission satisfies the requirements of 10 CFR 54.21 (b).

In accordance with 10 CFR 54.22, an applicant's LRA must include changes or additions to the

technical specifications (TS) that are necessary to manage the effects of aging during the

period of extended operation. In Appendix D to the LRA, the applicant stated that it had not

identified any TS changes as being necessary to support issuance of the renewed operating

licenses for FNP, Units 1 and 2. This adequately addresses 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 NRC regulations and the guidance provided by the SRP-LR. Sections 2, 3,

and 4 of this SER document the staff's evaluation of the technical information contained in the

LRA.

The final plant-specific supplement to the GEIS will document the staff's evaluation of the

environmental information required by 10 CFR 54.23 and will specify the considerations related

to renewing the licenses for FNP, Units 1 and 2. The staff will prepare this supplement

separately from this SER. As required by 10 CFR 54.25, the ACRS will issue a report to

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

will incorporate the ACRS report, once it is issued. Section 6 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 address the NRC's five (5) performance goals in safety, security, openness,

effectiveness, and management. An interim staff guidance (ISG) is documented for use by the

NRC staff, industry, and interested stakeholders until it is incorporated into the license renewal

guidance documents such as the SRP-LR and GALL report.

The following table provides the current set of ISGs that have been issued by the staff, as well

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as the SER sections in which the issues are addressed by the staff. - -

ISG lsie- Adu poset - SE-ionihi-

(A pprod ISG No.) ' Z" ' . - ';•a-:

GALL report This ISG clarified that GALL report contains one N/A -

presents one acceptable way, and not the only way to

acceptable way to manage aging for license renewal.

manage aging -

effects

(ISG-1)

Station Blackout The license renewal rule 10 CFR 54.4(a)(3) 2.5.2

Scoping (SBO) includes 10 CFR 50.63(a)(1)-SBO.

(ISG-2) ; ,

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 EDGs.

The offsite power system'should be included

within the scope of license renewal.

Concrete Aging Lessons learned from the GALL demonstration 3.5.2.1

Management project indicated that GALL is not clear whether 3.5.2.2.1

Program concrete requires an AMP. 3.5.2.2.9

(IS G -3) ._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _-

Fire Protection (FP) This ISG clarifies the staff position for wall 3.0.3.2.6

System Piping thinning of FP piping s~ystem in GALL AMPs'

(ISG-4) XI.M26 and XI.M27.

The staff's new position is 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. . -

Testing of sprinkler heads should be performed

every 50 years and 10 years'after initial service.

This ISG eliminates the Halon/carbon dioxide

system inspections for charging pressure, valve

- -. line ups, and automatic mode of operation test

from- GALL; the staff considers these test

verifications to be operational activities.

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.1

ISG Issue u ;rpose SR Section,:

(Approved ISGNO.) t' - H -

Identification and The ISG includes fuse holders AMR and AMP 2.1.3.2.3

Treatment of (i.e., same as terminal blocks and other 3.0.3.2.8

Electrical Fuse electrical connections). 3.6.2.3.2

Holders

(ISG-5) 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 agerelated failures from aging stressors such as

vibration, thermal cycling, mechanical stress,

corrosion, and chemical contamination.

The staff finds that visual inspection of fuse

clips is not sufficient to detect the aging effects

from fatigue, mechanical stress, and vibration.

The ISG Process This ISG provides clarification and update to the N/A

(ISG-8) ISG process on Improved License Renewal

Guidance Documents.

Standardized Format The purpose of this ISG is to provide a N/A

for License Renewal standardized license renewal application format

Applications for the 2003 applicants.

(ISG-10)

1.5 Summary of Open Items

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

There was no such items identified in the Draft SER dated October 15, 2004.

1.6 Summary of Confirmatorv Items

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

resolution, but the resolution has not yet been formally submitted to the staff. There was no

such items identified in the Draft SER dated October 15, 2004.

1.7 Summary of Proposed License Conditions

As a result of the staff's review of the LRA for FNP, Units 1 and 2, including subsequent

information and clarifications provided by the applicant, the staff identified three proposed

license conditions.

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

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

issuance of the renewed licenses.

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

Supplement and Appendix A of this SER to be completed prior to the period of extended

operation or as noted in Appendix A of this SER.

The third license condition is as follows:

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

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

the configuration of the specimens in the capsule. Any changes to the capsule

withdrawal schedule, including spare capsules, must be approved by the NRC prior to

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

Any changes to storage requirements must be approved by the NRC, as required by 10

CFR Part 50, Appendix H.

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2. STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW.

2.1 Scoping and Screening Methodology

2.1.1 Introduction

Title 10, Section 54.21, of the Code of Federal Regulations (10 CFR 54.21), 'Contents of

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

an integrated plant assessment (IPA). Furthe'rmorethe IPA must list and identify those - .

structures and components (SCs) that are subject to an aging management review (AMR) from

all of the systems, structures, and components (SSCs) that are within the scope of license

renewal in accordance with 10 CFR 54.4.

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

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

Farley Nuclear Plant (FNP) within the scope of license renewal and the SCs that are subject to

an AMR. The staff reviewed the applicant's scoping and screening methodology to determine if

it meets the scoping requirements stated in 10 CFR 54.4(a) and the screening requirements

stated in 10 CFR 54.21.

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

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

Licenses for Nuclear Power Plants," (the Rule), the Statement of Considerations (SOC) for the

Rule, and the guidance presented by the Nuclear Energy Institute (NEI), Industry Guideline for

Implementing the Requirements of 1 0 CFR Part 54-The License Renewal Rule," Revision 3,

March 2001 (NEI 95-10). In addition, in developing this'methodology, the applicant considered

the correspondence between the U.S. Nuclear Regulatory Commission (NRC) and other

applicants and/or'the NEI.

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, "Scoping and Screening Methodology," of the'LRA, the

applicant'described the process used to identify the'SSCs that meet the license renewal:

scoping criteria under 10 CFR 54.4(a), as well as the process used to' identify the SCs that are

subject to an 7AMR, as 'required by 10 CFR 54.21 (a)(1).

Additionally, Section 2.2 ("Plant Level Scopinig'Results"),' Section 2.3 ("System Scoping and

Screening Results: 'Mechanical Systems"), Section 2.4 ("Scoping and Screening Results:

Structures"),'and Section 2.5 ("Scoping and Screening Results: -Electrical") of the LRA amplify

the process that the applicant uses to identify the SCs that are subject to an AMR. Section 3 of

the LRA, "Aging Management Review Results," contains the following information:

Section 3.1, "Aging Management of Reactor Vessel, Internals, and Reactor Coolant

System" . *

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* Section 3.2, "Aging Management of Engineered Safety Features Systems"

* Section 3.3, "Aging Management of Auxiliary Systems"

* Section 3.4, "Aging Management of Steam and Power Conversion Systems"

* Section 3.5, "Aging Management of Containment, Structures and Component Supports"

* Section 3.6, "Aging Management of Electrical Components"

Section 4 of the LRA, 'Time-Limited Aging Analyses," contains the applicant's identification and

evaluation of time-limited aging analyses (TLAAs).

2.1.2.1 Scoping Methodology

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

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

requirements of the 10 CFR 54.4(a) scoping criteria. The following sections present the

applicant's scoping methodology, as described in the LRA.

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 (SR) and nonsafetyrelated (NSR) SSCs and SSCs credited with demonstrating compliance with certain regulated

events in LRA Section 2.1.2, "Application of Scoping Criteria in 10 CFR 54.4(a)." The following

sections describe the scoping approaches specific to each of the three 10 CFR 54.4(a) scoping

criteria.

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

In LRA Sections 2.1.3.1, "SR Criteria Pursuant to 10 CFR 54.4(a)(1)," and 2.1.4, "Identification

of Structures and Components Subject to Aging Management Review," the applicant discussed

the scoping methodology as it pertains to safety-related criteria in accordance with 54.4(a)(1).

With respect to the safety-related criteria, the applicant stated that the SSCs within the scope of

license renewal include safety-related SSCs that are relied upon during and following designbasis events (DBEs). The DBEs considered are consistent with the FNP, Units 1 and 2, current

licensing basis (CLB). The final safety analysis report (FSAR), with emphasis on Chapters 6

and 15, provides the DBE analyses for FNP Units 1 and 2. Chapter 2 of the FSAR describes

natural phenomena and external events. Chapter 3 of the FSAR describes structures designed

to withstand DBEs, natural phenomena, and external events. The applicant identified the plant

functions that meet the criteria of 10 CFR 54.4(a)(1) and are within the scope of license

renewal. The applicant listed these functions in the scoping database, along with the systems

and structures required to perform these safety-related functions. Tables 2.2-1a through 2.2-1f

of the LRA list the systems and structures, and plant-level scoping results.

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

In LRA Sections 2.1.3.2, "NSR Criteria Pursuant to 10 CFR 54.4(a)(2)," 2.1.4, "Identification of

Structures and Components Subject to Aging Management Review," and 2.1.5.9,

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10 CFR 54.4(a)(2) Scoping (ISG-09),' the' applicant discussed the' scoping methodology -as it

related to the NSR criteria in acc6rdance 'with 10CFR 54.4(a)(2). --With' respect to the NSR

criteria, the applicant stated, in part, thatdit ha'd peftried a review to identify the NSR SSCs

whose failure could prevent satisfactory accomplishment of the SR intended functions identified

in 10 CFR 54.4(a)(1). Th6 NSR SSCs that are within the scope of license renewal for FNP,

Units 1 and 2, fall into two categories-(i) NSR SSCs that functionally support the'6peration of

SR SSCs, and (2) NSR SSCs whose failure could cause an interaction with safety-related

SSCs that could potentially result in the failure of the SR SSCs to' perform their intended safety

functions. S6oping of SSCs for the criteria1of lb bFR 54.4(a)(2) for FNP considered those

failures identified in the CLB and plant-specific operating experience and any'industrywide

operating experience that is specifically applicable to FNP.

The applicant used a systematic process t6identify ichanical comiponents subject to' the

10 CFR 54.4(a)(2) criteria. Specifically, the applicant established five categories of components

based on a review of FNP's CLB documents, plant and industry operating experience, arid

NRC's guidance on scoping, including draft interim staff guidance (ISG)-09, 'X10 CFR 54.4(a)(2)

Scoping." For each category of equipment, the applicant employed a combination of methods,

including plant system walkdowns, plant piping and instrument drawing reviews, and evaluation

of system technical documentation. The five categories of mechanical components that meet

the requirements of 10 CFR 54.4(a)(2) include the following:

(1) high-energy NSR piping and mechanical components

(2) NSR piping and components attached to SR piping

(3) nonattached NSR piping

(4) relief paths for SR relief valves and SR pump recirculation lines

(5) NSR features to maintain penietration roo'6r filtration negative pressure envelope

The applicant placed the NSR civil SSCs that are in proximity to SR civil/mechanicaVelectrical

SSCs, and whose failure could inhibit or adversely affect the performance'of SR SSC6 br SR

functions, within the scope for aging effects evaluation. The applicant used a spaces approach

to scope civil features inside structures housing SR SSCs that could cause an'interaction with

safety-related SSCs potentially resulting in the failure of the SR SSCs to perform their intended

safety functions.

With respect to electrical systems, the South6rn Nuclear Operating Company (SNC) design

incorporates the isolation of SR componernts-from NSR components,'such that'SSCs that could

prevent or adversely affect a function that 'neets-the criterion of 10 -CFR 54.4(a)(1) are

classified as SR. 'Therefore, the applicat placed these components in scope underan

10 CFR 54.4(a)(1) rather than under 10 CFR 54.4(a)(2).

Anplication of the Scoping Criteria in 10 CFR 54.4(a)(3)

In LRA Sections 2.1.3.3, "Other Scoping Pursuant to 10 CFR 54.4 (a)(3)," 2.1.5.2; USBO

Scoping'(ISG-02)," 2.1.5.4, "Fire Protection'Systemn Piping (ISG-04)," and 2.1.5.7, Scoping

Guidance 'for Fire' Protection Systenms Str`Uctuires, rnd Components (ISG-07)," the applicant

discussed the scoping methodology as it relates to the regulated event criteria, in accordance

with 10 CFR 54.4(a)(3).' With respect tid the escoping criteria related to 10 CFR 54.4(a)(3), the

applicant evaluated all regulated events'including (1) fire protection (FP), (2) environmental

qualification (EQ), (3) pressurized thermhal shbck (PTS), (4) anticipated transient without scram

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(ATWS), and (5) station blackout (SBO). For each regulated event, the applicant identified and

reviewed the applicable FNP plant-specific licensing basis documents, such as the FSAR,

safety evaluation reports (SERs), licensing correspondence, plant-controlled databases,

calculations, and analyses to establish the scoping determinations. Initially, the applicant

included within the scope of license renewal the SSCs relied upon in safety analyses or plant

evaluations to perform a function that demonstrates compliance with the applicable regulations.

In summary, the applicant included in the scope of license renewal the SSCs relied on in safety

analyses or plant evaluations to perform an intended function that demonstrates compliance

with NRC regulations for FP, EQ, PTS, ATWS, and SBO, in accordance with the criteria of

10 CFR 54.4(a)(3).

2.1.2.1.2 Documentation Sources Used for Scoping and Screening

In LRA Section 2.1.2, "Information Sources," the applicant stated that it had reviewed

information from the following sources during the license renewal scoping and screening

process:

* final safety analysis report

* current licensing basis information including technical specifications and docketed

licensing correspondence

* functional system descriptions

* technical position papers prepared to support scoping evaluations of the regulated

events identified in 10 CFR 54.4(a)(3)

* Maintenance Rule summary reports and scoping information

* plant drawings

* probabilistic risk assessment model

The applicant stated that it used this information to identify the functions performed by plant

systems and structures. It then compared these functions to the scoping criteria in

10 CFR 54(a)(1-3) to determine if the associated plant system or structure performed a license

renewal intended function. It also used these sources to develop the list of structures and

components subject to an AMR.

2.1.2.1.3 Plant- and System-Level Scoping

In LRA Section 2.1.3, "Scoping Procedure," the applicant described the scoping methodology

for safety-related and nonsafety-related systems and structures and for equipment relied upon

to perform a function for any of the five regulated events described in 10 CFR 54.4(a)(3).

The FNP scoping process began with development of a comprehensive list of plant functions

focused on identifying SSCs as defined by 10 CFR 54(a). Functions are defined as required

actions of a system or structure. The applicant compiled this preliminary list by reviewing the

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FSAR, licensing correspondence, design-basis documents (DBDs) rand design drawings, as

applicable. It then combined or separated the preliminary functions as necessary, which

resulted ia final set of plant functions'to'cbnsider'for scoping. The applicant evaluated each

final plant function against the 10 CFR 54.4(a) cdriteria to determine if it mnet the definition of an

intended function'for license renewal. An expert panel'convened to review the list of identified

intended functions and the criteria that brought each into the scope of license renewal. The

applicant then identified the systems and structures that perform each intended function.

2.1.2.1.4 Component-Level Scoping -

After the applicant identified the intended functions of systems or structures within the scope of

license renewal, it performed a review to determine which components of each in-scope system

and structure supported license renewal intended functions. The applicant considered the

components that supported intended functions to-be within the scope of license renewal and

screened them to determine if an AMR was required.

The applicant considered three component classifications (mechanical, civil and structural, and

electrical) during this stage of the scoping methodology. The following discusses the scoping

methodology for each of these component cla ssifications.

Mechani6al Component Sconin'

The applicant described the scoping methodology for components within safety-related and

nonsafety-related mechanical systems in'Section 2.1.4 of the LRA; 'For each mechanical

system determined to be within th's'cope of license renewal, the applicant developed a system

evaluation boundary to identify the set of structures and components necessary to perform the

intended functions for the given mechanical system.' These evaluation boundaries included

sets of piping and instrumentation diagrams (P&lDs) for each system. From the boundary

diagrams, the'applicant identified complhnehts that were required to ensure the system could

perform its intended functions. Then, the applicaht grouped them into relevant component

types associated with each in-scope fun6tion and listed them in thte scoping and screening

database for further analysis.

Structural Component Scoping

Section 2.1 .4 of the LRkdiscusses'the scoping methodology associated with the structures and

structural components.' "After'it had identified SR structures and NSR 'structures that could'-

impact SR SSCs, the applicant'developed evaluation boundaries for the various plant structures

.within th'e scope of license'renewal. Generally, the applicant applied the philosophy that a

boundary for a building'or structure is the entire building including base slabs, foundations, -

walls, beams, slabs, and steel superstructure. The applicant then identified the various types of

structural elements, materials, and environments that make up the buildings and structures and

listed them in the license renewal database. The applicant started with thelist of structures and

structural elements in NUREG-1 801 and NEI 95-10 and supplemented that list with

components' unique to FNP by' reviewing [plant-specific structural drawings. In this way, the

applicannt was able to compile a comprehensive list of all plant structures and structural

elements within'the' scope of license renewal:

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Electrical and I&C Comoonent Scopina

The applicant described the scoping process associated with electrical and l&C systems and

components in Section 2.1.4 of the LRA. For these systems, the applicant elected to use a

bounding or spaces approach as described in NEI 95-10. As a result, the electrical/l&C

component types used throughout the plant were identified without regard to specific

electrical/I&C system intended functions. Instead, the applicant identified all electrical and l&C

component types in use at FNP and listed them in the license renewal database using the

guidance in Appendix B to NEI 95-10. The applicant supplemented this list with any unique

plant electrical components by reviewing plant component information, drawings, and technical

information. The applicant organized the electrical component types into commodity groups

such as breakers, switches, and cables. The applicant identified these electrical and l&C

component commodity groups from a review of plant documents, controlled drawings, the plant

equipment database, and interface with the parallel mechanical and civil/structural screening

evaluations.

2.1.2.2 Screening Methodology

After determining the 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 LRA Section 2.1.4, "Identification of Structures and

Components Subject to Aging Management Review," the applicant discussed the screening

activities as they related to the SSCs that are within the scope of license renewal. The

applicant divided the screening portion of the integrated license renewal plant assessment into

three engineering disciplines-mechanical, civiVstructural, and electrical and I&C.

2.1.2.2.1 Mechanical Component Screening

After the component-level scoping for mechanical systems, the applicant screened the

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

Section 2.1.4.1, "Mechanical Systems," that it screened each system identified to be within the

scope of license renewal. This process evaluated the individual structures and components

included within in-scope mechanical systems to identify specific structures and components that

required an AMR. The applicant evaluated electrical interface components associated with inscope mechanical systems under the electrical component scoping methodology. The

applicant evaluated each mechanical component identified in the scoping phase and entered in

the LR database against the screening criteria in 10 CFR 54.21 (a)(1). All components that

contribute to the performance of an intended function, perform their function without moving

parts and without a change in configuration or properties, and are not subject to replacement

based on a qualified life or specified time period (i.e., those that are passive and long-lived) are

subject to an AMR.

2.1.2.2.2 Structural Component Screening

After determining which SSCs were within the scope of license renewal, the applicant

implemented a process for determining which SCs would be subject to an AMR, in accordance

with the requirements of 10 CFR 54.21(a)(1). In LRA Section 2.1.4, "Identification of Structures

and Components Subject to Aging Management Review," the applicant discussed the

screening activities related to civil and structural SCs within the scope of license renewal.

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These screening activities consisted of the identification of passive components, long-lived

components, component intended functions, consumables, and coriponent replacement based

on performance or condition. 'The applicant relied on the guidance'in NEI 95-10 and Chapter 2

of the Standard Review Plan (SRP) to developbthe plant-specific listing of passive components

of interest during the' review.

2.1.2.2.3 ElectricaVl&C Component Screening'

After the component-level scoping for electrical l&C systems, the applicant screened the

efectricaVl&C-components to identify those'subject to an AMR. In Section 2.1.4 of the LRA, the

applicant described the methodology used to screen electricaVl&C components. Specifically,

the applicant applied the criteria of 10 CFR 54.21 (a)(1 )(i) and (ii) to identify component

commodity groups that perform their intended functions without moving parts or without a

change in configuration or properties (refr&red to as passive components) and excluded those

components or commodity groups that are subject to replacement based on a qualified life or

specific time period (referred to as short-lived components). The applicant utilized the guidance

of NEI 95-10 and EPRI TR1 0003057, 'Liceinse Renewal Electrical Handbook," to identify these

components. Electrical components included in tfie'plant Environmental Qualification Program

are replaced on a specified interval basedboI a qualified life. Therefore, components in the

Environmental Qualification Program do nbt'meet the long-lived criteria of

10 CFR 54.21 (a)(1 )(ii) and are short-lived per the regulatory definition, and thus are not subject

to an AMR. Using these screening criteria, the applicant determined that for FNP, the electrical

component types that require an AMR are cables, connectors, buswork, oil-static cables, and

various switchyard components.

2.1.3 Staff Evaluation

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

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

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

(SRP-LR). The following regulations form the basis for the acceptance criteria for the scoping

and screening methodology review:

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

Rule

* 10 CFR 54.4(b), as it relates to the identification of the intended functions of 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 compdnients subject to an AMR

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

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

contained in NUREG-1800:

* Section 2.1, 'S6oping and Screening Methodology," to ensure that the applicant

describes a process for identifying SSCs that are within the scope of license renewal, in

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accordance with the requirements of 10 CFR 54.4(a)(1), (a)(2), and (a)(3)

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

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

Structures," and Section 2.5, "Scoping and Screening Results: Electrical,' to ensure

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

electrical components at the FNP that are subject to an AMR in accordance with the

requirements of 10 CFR 54.21 (a)(1) and (a)(2)

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

offices in Birmingham, Alabama, from November 18-21, 2003. The audit focused on ensuring

that the applicant had developed and implemented adequate guidance to conduct the scoping

and screening of SSCs in accordance with the methodologies described in the application and

the requirements of the Rule. The audit team reviewed implementation procedures and

engineering reports describing the applicant's scoping and screening methodology. In addition,

the audit team conducted detailed discussions with the applicant on the implementation and

control of the License Renewal Program and reviewed administrative control documentation

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

process. The audit team reviewed the applicant's processes for quality assurance with respect

to development of the LRA and training and qualification of the LRA development team. The

audit team also reviewed a sample of system scoping and screening results reports for the

residual heat removal/low head safety injection, auxiliary feedwater (AFW), main steam, and

open-cycle cooling water systems, to ensure that the applicant had appropriately implemented

the methodology outlined in the administrative controls and that the results were consistent

with the CLB. The audit team documented its review in an audit report issued on September 8,

2004 (ML042520177). 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 SER.

2.1.3.1 Scoping Methodology

The audit team reviewed implementation procedures and engineering reports describing the

scoping and screening methodology implemented by the applicant. These SNC procedures

include "License Renewal Plant Farley Scoping Procedure,' SP-LR-2-2, Version 2.0; "License

Renewal Plant Farley Boundary Procedure," SP-LR-2-4, Version 2.0; "License Renewal Plant

Farley Screening Procedure," SP-LR-2-5, Version 2.0; "License Renewal Plant Farley Database

Control Procedure," SP-LR 2-9, Version 3.0; and "License Renewal Plant Farley Definitions and

References Procedure," SP-LR 2-1, Version 2.0.

The team found that the scoping and screening methodology instructions were consistent with

Section 2.1 of the LRA and were of sufficient detail to provide the applicant with concise

guidance on the scoping and screening implementation process to be followed during the LRA

activities. In addition to the implementing procedures, the audit team reviewed supplemental

design information including system functional descriptions, system drawings, and selected

licensing documentation, which the applicant relied upon during the scoping and screening

phases of the review. The team found these design documentation sources to be useful for

ensuring that the initial scope of SSCs identified by the applicant was consistent with the plant's

CLB.

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The audit team reviewed the quality assurance controls used by the applicant to provide -'

reasonable' confidence that th6'LRA scoping a'nd screening methodologies were adequately

implemented. The audit team determined that the applicant utilized the following quality

assurance processes during the LRA development:

(1) Implemneritation of the scoping ard screening methodology was'governed by'written

procedures and guidelines. -

(2) The applicant developed aforral database for documentingr license renewal

information identified during scoping anid screening evaluations. This database was

considered the formal quality records of the LR implementation process, and was

controlled in accordance with written instructions. Access to the database was strictly

controlled. -

(3) All final scoping and screening information was developed by a' lead technical staff

member and independently reviewed by an additional technical staff member prior to

being reviewed and approved by thepro~gramima'nager.

(4) The scoping results were reviewed by an independent expert committee comprised

of senior experienced members of the Southern Company corporate engineering staff

and Farley Nuclear Plant personnel.

(5) The applicant conducted two nuclear quality assurance assessments of the process

to develop the LRA to validate the i mlementatio n process and the technical accuracy of

the application.

The audit team concluded that these quality assurance activities provided additional assurance

that LRA development activities were perforrmi6d consistently with the LRA development

guidance descriptions.

The audit team reviewed the applicant's implemnented traininig process to ensure the guidelines

and methodology for the-scoping and screening activities would be performed in a consistent

and appropriate manner. The applicant's LRA teiim consisted of several 'engineers who had

gained previous license renewal experience working on the Hatch Nuclear Plant (HNP), Units 1

and 2 LRA. This team was suppl6mented with'additional staff from the'SNC that were provided

with license renewal specific training p'rior'to'performing license renewal activities. The purpose

of the training was to provide a framework for ensurinig that the applicant's staff assigned to the

technical portion of the license renewal application acquired a fundamental level of knowledge

of the license renewal process and reggulatoryerequirements. The trainrig program consisted of

on-the-job training and mentoring-provided by engineers with prior'HNP LRA experience,

supplemented by'self-study of selected d66cUrehts, and lectures by those experienced in

various LRA topics. On-the-job-trairiing dco'sisted of senior 'engineers mentoring the'

less-experie'nced staff members orithe irplerifentition process, asd6scribed in written

instructions, associated with' scoping, screening and boundary development. The applicant's

license7 renewal team also developed an index of applicable license' renewal docuinmentation,

including industry and regulatory guidance,'whichth'e licernse renewal staff mehbe&6s were

required to read and sign acknowledging that they 'completed their self-study.' Engineers with

prior experience o6r'the HNP LRA'lireparati6`6 provided lectures on 'such topics as, scoping,

electrical spaces approach,-Aging Management Programs '(AMP), boundaries, screening, Aging

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I

Management Reviews (AMRs), and Time-Limited Aging Analysis (TLAA). A comprehensive

training qualification record for each staff member was compiled and maintained by the

applicant as part of the application development process.

The audit team reviewed completed qualification and training records of several of the

applicants license renewal staff, including both experienced and non-experienced members,

that performed scoping and screening activities. The audit team did not identify any adverse

findings. Additionally, based on discussions with the applicant's license renewal personnel

during the audit, the team determined that the applicant's license renewal staff were

knowledgeable on the license renewal process requirements and the specific technical issues

within their areas of responsibility.

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

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

In part, 10 CFR 54(a)(1) requires that the applicant consider all safety-related SSCs that are

relied upon to remain functional during and following DBEs to ensure the following functions:

* the integrity of the reactor coolant pressure boundary

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

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

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

10 CFR 50.67(b)(2), or 10 CFR 100.11 to be within the scope of license renewal

The NRC audit team found that the applicant appropriately incorporated the pertinent

safety-related SSCs into the scope of its License Renewal Program. The applicant did not rely

on its plant component Q-List as a starting point for identifying SSCs within the scope of the

Rule. Instead, the applicant developed an exhaustive list of plant functions with information

acquired from reviews of various FNP CLB source documents. Principal among those sources

was the updated final safety assessment report (UFSAR), technical specifications, documents

related to scoping for implementation of 10 CFR 50.65, the Maintenance Rule, and those

documents related to the FNP probabilistic risk assessment (PRA) model. Additional

information sources included docketed licensing correspondence, design information related to

various plant systems, and technical position papers.

The applicant's approach to satisfying the scoping requirements of 10 CFR 50.54(a)(1) was to

identify all safety-related intended functions required to be performed by the FNP units and to

subsequently identify the plant systems necessary to perform those intended functions. To

accomplish this, the applicant added more documentation to the review, including functional

system descriptions, which document the functional requirements and bases of FNP systems,

and plant drawings, which are useful for detailing the extent of necessary scope, the equipment

to be included therein, and spatial relationships. Additionally, the applicant developed a report,

"Review of Non-Chapter 15 FSAR Design Basis Events for Additional SSCs In-Scope for

License Renewal," which detailed a composite list of FSAR events to assist in identifying

system intended functions and systems credited with mitigation of those events. The audit

team reviewed the report and discussed it with the applicant. The team found the report to

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contain a concise and detailed evaluation of i'pproxirnately 40 evbrits along with appropriate

supporting referencest6 CLB docdurmentati6ri. '' ' '

In accordance with license renewal procedure'SP-R1E 2-2, an expert panel-reviewed the results

of the scoping process. Th'e'expert panel a"i6bh 'was effective in the development and

evaluation of safety-related functions.

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

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

scoping result reports to support these reviews, and discussed the methodology and results

with the applicant's personnel who were responsible for these evaluations.

Conclusion

The audit team reviewed a sample of the license renewal database 10 CFR 54.4(a)(1) scoping

results and discussed therMrethodology an'd'results with the applicant's license renewal'project

personnel. The team determined that the applicant had identified and used pertinent

engineering and licensing information to identify the SSCs required to be in scope in

accordance with the 10 CFR 54.4(a)(1) criteria.- Thereforeon the basis of this sample review,

discussions with the aMplicant, and review of the applicant's scoping process, the staff

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

scoping criteria'of 1i0 CFR'54.4(a)(1) wads'adequate.

ADplication of the Scopin6 Criteria in 10 CFR 54.4(a)(2)

In part, 10 CFR 54(a)(2) requires that the applicant consider all nonsafety-related SSCs whose

failure could prevent satisfactory accomplishment of any of the functions identified in 10 CFR

54(a)(1)(i),1O CFR 54(a)(1)(ii),' or 10 CFR 54(a)(1)(iii) to be within'the scope of license renewal.

By letters dated Dedember 3, 2001, and Mairch 15, 2002, the NRC issued a staff position to the

NEI which provided staff bipectations for deteimining'what SSCs meet the 10 CFR 54.4(a)(2)

criterion. The December 3, 2001 letter (ADAMS Accession No. ML01 3380013) provided

specific examples of operating experience which identified pipe failure events (summarized in

Information Notice (IN) 2001-09, "Main Feedwater'System Degradation in Safety-Related ASME Code Class 2 Piping Inside the'Containmrrient 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

(ADAMS Accession No. ML020770026) further described the staff's expectations for-the

evaluation of nonpiping SSCs to determine which additional nonsafety-related SSCsare within

scope. The position states that applicantsrshouJld rnot consider hypoth6tical failures, but rather

should base their evaluation"on the' plant'sCLB engineering judgeme't and analyses, and

relevant operating experience. The paper further dekcribes operating experience as all

documented plant-specific and industrywide experience that can be used to determine the

plausibility'f a failure.- Do&umentation would include NRCigeneric communications and event

reports, plant-specific co0ndition reports, iridustry'reports'such as SOERs, and engineering

evaluations.

The appiicant documented its methodology for performing 10 CFR 54.4(a)(2) scoping ofnonsafety-related SSCs in the'6'implemintation pr'ocedure "Scoping Methodology for, Non--

Safety-Related Equipment that Could Affect Safety-Related Equipment,10 CFR 54.4(a)(2)."

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The procedure described the current regulation and the interim staff position regarding scoping

of SSCs with respect to the 10 CFR 54.4(a)(2) criteria, and the applicant's methodology,

discussion, and results regarding scoping in accordance with the Rule criteria. The report

specifically states that for mechanical systems and components, the potential for meeting the

10 CFR 54.4(a)(2) criteria exists for both connected and nonconnected NSR SSCs. The

applicant evaluated the following five categories of NSR mechanical components:

(1) NSR piping attached to SR piping

(2) high-energy NSR piping

(3) low-energy NSR piping that has a spatial relationship to SR SSCs

(4) piping that is used for relief valve flowpaths and SR pump recirculation paths

(5) floor drain traps and plugs that support the maintenance of the PRFS pressure

boundary

In keeping with the NEI draft position on NSR SSCs that could adversely affect SR SSCs, SNC

used a process to identify SR targets and NSR threats in a given area of FNP. To determine

the potential for interaction between credible threats and valid targets, the applicant used the

piping physical layout drawings for NSR systems in combination with electrical equipment

layout and instrument layout drawings. Where an NSR pipeline or component was located in

the same room or area as an SR electrical component, that room was identified for later

walkdown. The applicant listed these potential interactions and performed walkdowns for

rooms with potential interactions.

In those cases where the applicant identified a credible interaction, the applicant recorded that

potential interaction for further evaluation to determine if that interaction could affect the SR

component. If this evaluation found a potential adverse affect on an SR component, the NSR

SSC was brought into scope.

For mechanical components, the applicant created a set of separate functions to account for

the NSR mechanical components. The following five functions are in scope only for criterion

10 CFR 54.4(a)(2):

(1) F050-attached piping

(2) F051-high-energy lines

(3) F053-NSR SSCs spatial interaction with SR SSCs

(4) F054-pump recirculation and safety relief valve vent paths

(5) F056-PRFS pressure boundary drain traps and plugs

The applicant presented the results of this review in tables within the report and appended the

license renewal database to include those components brought into scope as a result of the

review.

On the basis of its review of the LRA, the applicant's scoping and screening implementation

procedures, and discussions with the applicant during audit conducted from November 18 to

November 21, 2003, the staff determined that it needed additional information to assess certain

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aspects of the'applicant's evaIuation of the 10 'CFR 54.4(a)(2) c'riterid.' By letter dated.

December 12, 2003, the staff 'requested additional information regarding the scoping

methodology associated with the 10 CFR 54.4(a)(2) evaluation. This was request for additional

information (RAI) 2.1-1: In RAI 2.1-1, the st'aff asked the applicant'to address the following five

issues: - '

(1) the basis for use of proceduralized criteria that could exclude certain NSR

equipment from the scope of license reneWal (e.g., NSR equipment could be excluded

from scope if it is more than 20 feet away from an SR electrical component)

(2) the use of operating experience for determining that certain gas-filled SSC failures

were not credible

(3) the basis and/or justification for lirriiting the valid target to only an electrical SR SSC

(4) the basis for considering NSR comiponents up to (emphasis added) the next

equivalent seismic anchor (or physical 'restrainf in the third direction) to be within the

scope of 10 CFR 54.4(a)(2) and evaluated for the effects of aging management, and

clarification as'to whether the seismic anchor itself is within scope

(5) the basis for not including a portion of the NSR piping (3-in. HCC-321 attached to

valve QV-791 B) in the service water -system which appeared to meet the initial scoping

criteria for attached NSR piping described in the LRA position paper "License Renewal

Position Evaluation and Disposition," but was not included within the scope of license

renewal ...

The applicant responded to the staff's RAI in letters dated January 9, 2004, March 31, 2004,

and April 16,2004. In addition, the'staff held conference calls with the applicant on February 5,

2004,'March 1, 2004,' and March 18, 2004, to clarify the responses to the RAI. In its letter

dated January 9, 2004, the applicant initially rdplied to each of the staff's requests.

With respect to the first issue regarding the basis for the 20-foot criteria, the applicant stated

that the primary basis for the criteria was discussions within the industry that considered 20 feet

to be an acceptable distance for spray effects from low-energy pipes. In most cases, the 20-

foot criteria encompassed the entire confinres of a room where SR and NSR SSCs were

located. However, notable exceptions included the heat-exchanger rooms, the corridors, the

mechanical penetration rooms, and the lower equipment room within the auxiliary building. In,-

most cases, the SR and NSR equipmrient in these'rooms were in fact brought into scope

because they rmet one of the other scopinhg 'criteriai'

The staff reviewed the applicant's response, concluded that the applicant did not provide

sufficient rationale for the use of the 20-foot criteria,'and requested the applicant to provide a

technical basis for the criteria or review its approach and determine if additional SSCs should:

be included in scope. As a result, the applicant revised its scoping methodology to remove the

20-foot criteria and performed a suople'me'ntal'scoping review based on a spaces approach. By

letter dated April 16,2004,-the applicant described the revised scoping methodology based on

the spaces approach. 'The staff 'reviewed thii r6sponse and finds that it adequately addresses

the potential for interaction between NSR and SR SSCs, conrsistent with the staff's position -

described above. Specifically, the applicant'stated that it will consider all fluid-filled NSR SSCs

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A

to be in scope if those NSR SSCs are located in the same space as the SR SSCs. For the

purposes of the review, a space was defined as the room in which the SR and NSR

components are located. In addition, if the SR SSC is determined not to be vulnerable to the

effects of spray or leakage, then the NSR SSC of interest would not be brought into scope

because it could not prevent or adversely affect the SR component's performance of its safety

function. In broadening its scoping evaluation approach, the applicant also will consider the

impact of NSR fluid-filled SSCs on both mechanical and structural SR SSCs in addition to the

active electrical components already considered within its 10 CFR 54.4(a)(2) evaluation. As a

result of the revised 10 CFR 54.4(a)(2) methodology, the applicant brought into scope

additional NSR SSCs and provided AMR information for each. Sections 2.2 and 3 of this SER

evaluate these topics.

With respect to the second issue regarding the identification of the nonfluid-filled systems

evaluated and the operating experience applied to the evaluation, the applicant stated that it

conducted the review in accordance with the staff's guidance and included both nonfluid-filled

piping and ductwork SSCs. The applicant considered the operating environment for each of

these SSCs and reviewed the plant's CLB and plant-specific and industrywide operating

experience (i.e., NRC generic communications, industry reports, and the plant-specific

corrective action database) to determine if any credible aging effects resulting in failures of

these SSCs could impact the SR SSCs in proximity.

The staff reviewed the applicant's response and concluded that the applicant had adequately

described its process for evaluating the potential for nonfluid-filled SSCs to cause the failure of

SR SSCs. This description is consistent with the staff's position regarding the scoping of SSCs

in accordance with the requirements of 10 CFR 54.4(a)(2) described above.

With respect to the third issue regarding limiting the valid target to only an electrical SR SSC,

the applicant stated that it had performed an evaluation to determine if mechanical or structural

components were susceptible to failures from dripping or spraying of oil or water and had not

identified any such failures. The applicant stated that this assessment was also based on the

assumption that any such spraying or dripping on mechanical or structural SSCs would be

limited in duration because visual identification of the spray or leakage was likely before it would

pose a failure concern.

The staff reviewed the applicant's response and concluded that the applicant did not provide an

adequate justification for limiting targets to electrical SSCs only. As part of the review, the staff

asked the applicant to provide additional justification for the determination that mechanical and

structural SSCs would not be susceptible to such effects or perform a supplemental evaluation

to determine what, if any, additional NSR SSCs should be brought into scope. Specifically, the

staff requested that the applicant provide a basis showing that the mechanical and structural

SSCs were qualified to withstand the environment created as a result of the spray or dripping of

such fluids and provide the rationale for the assumption that any such exposure would be

limited in duration.

As a result, the applicant revised its scoping methodology to consider both mechanical and

structural SR SSCs as potentially valid targets, and it performed a supplemental scoping review

based on this criteria. By letter dated April 16, 2004, the applicant described the revised

scoping methodology. The staff reviewed this response and finds that it adequately addresses

the potential for interaction between NSR and SR SSCs and is consistent with the staff's

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position'described above. 'As a result-of the revised 10 CFR 54.4(a)(2) methodology, the

applicant brought into'scope additional NSR SSCs and provided AMR information for each.

Sections 2.2 and 3 of this SER evaluate these topics. :

With respect to the fourth issue regarding the basis'fdr-considering NSR components up to the

next equivalent seismic anchor (or physical restraint in the third direction) to be within the scope

of 10 CFR 54.4(a)(2- and clarificationas to whether the seismic anchor itself is within scope,

the applicant stated that the seismic anchor'(as defined) is included within scope. Additionally,

the applicant determined that the use of the equivalent anchor point determined to be a physical

restraint in the third cardinal direction is consistent with the CLB and the seismic analysis

pertaining to FNP, Units 1 and 2. Specifically, the applicant reviewed and established that the

plant seismic analysis confirmed that the NSR SSCs (including piping and any in-line

component) necessary for the qualification of the SR piping was included within that portion of.

the piping systems up to the'physical constraint in the'third direction. As an additional -,

assurance that SR SSCs would be preserved during a seismic event, the applicant also placed

within scope all piping supports and anchors within all seismic Category 1 buildings, regardless

of thedsafety classification of those components. --

The staff reviewed the'applicant's response and concluded that the applicant had adequately

described its process for establishing the next equivalent seismic anchor consistent with the

CLB and the seismic analysis' pertaining to FNP, Units 1 and 2,-and the staff's position

regarding-the'scoping of SSCs in accordance with the requirements of 10 CFR 54.4(a)(2)

described above.

With respect to the final issue regarding the basis for not including a portion of the NSR piping

(3-in. HCC-321 attached to valve QV-791 B) in the service water system which appeared to

meet th6 initial scoping criteria for attached NSR piping described in the LRA position paper

"License Renewal Position Evaluation and Disposition," the applicant stated that the portion of

piping identified by the audit team was in fact within the scope of license renewal although it

was not highlighted on the working drawing to reflect this. Additionally, the applicant reviewed

the system boundary drawings to'assure that the remaining attached NSR piping was properly

captured within scope.' By letter dated March 31; 2004, the applicant confirmed that the portion

of NSR piping was in scope in accordance with its 1 0 CFR 54.4(a)(2) evaluation.

The staff reviewed the applicant's response and concluded that the applicant did include the

portion of NSR piping within scope and determined that the remaining attached piping was

properly evaluated in accordancedwith its initial scoping criteria.

Conclusion'

As part of the review of the applicant's'scoping methodology, the audit team also reviewed a

sample of the license renewal database 10 CFR 54(a)(2) scoping results to determine if the

scoping methodology adequately identified nonsafety-related SSCs meeting the scoping criteria

of 10 CFR 54.4(a)(2). On the basis of the additional information supplied by the applicant,

including expansion of the systems within the scope of license renewal and addition of new

portions of systems within scope as a -result of the revised methodology, determination of the

credible failures which could impact the ability of safety-related SSCs to perform their intended

functions, evaluation of relevant operating experience, incorporation of identified nonsafetyrelated SSCs into the applicant's AMPs, and the results of NRC inspection and audit activities,

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I

the staff concludes that the applicant has supplied sufficient information to demonstrate that all

SSCs that meet the 10 CFR 54.4(a)(2) scoping requirements have been identified as being

within the scope of license renewal. Therefore, the staff considers RAI 2.1-1 to be closed.

Application of the Scoping Criteria in 10 CFR 54.4(a)(3)

In part, 10 CFR 54(a)(3) requires that the applicant consider all SSCs relied on in safety

analyses or plant evaluations to perform a function that demonstrates compliance with the

Commission'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 license renewal.

The applicant documented its methodology for performing the scoping of SSCs in accordance

with 10 CFR 54.4(a)(3) in implementation procedure SP-LR-2-2 and the technical position

papers developed by the applicant for each regulated event applicable to the FNP, Units 1 and

2.

The applicant performed the initial scoping for regulated events by evaluating CLB information

relevant to each regulated event to identify if the structure or system met the scoping criteria of

10 CFR 54.4(a)(3). For each event, the applicant developed a position paper describing the

relevant Rule requirements, a functional description of the implementation of that requirement

at the FNP, specific information regarding systems and components credited for the event, the

process to identify the scoping boundaries associated with the systems credited, the intended

functions applicable to the requirement, information on how to record the results of the

evaluation in the license renewal database, a list of CLB information sources used for the

analysis, and a list of systems and components determined to be within scope for the given

regulated event. During the scoping and screening methodology audit, the applicant stated that

use of the position papers ensured consistent scoping results and eliminated the need to review

CLB documents when evaluating each plant structure or system against the 10 CFR 54.4(a)(3)

scoping criteria.

In an April 1, 2002, letter from D. Matthews to A. Nelson and D. Lochbaum, the staff provided

guidance on the scoping of equipment relied on to meet the requirements of the SBO rule,

10 CFR 50.63. In this letter, the staff noted that, consistent with the requirements specified in

10 CFR 54.4(a)(3) and 10 CFR 50.63(a)(1), 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. In Section 2.1.3.3.5 of the LRA, the applicant stated that the SBO

scoping effort identified structures and components of the offsite power system for each plant

required to restore power from the onsite switchyard down to the safety-related busses in the

plant. The applicant also stated that the plant offsite power system and these structures and

components were classified as satisfying criteria 10 CFR 54.4(a)(3) and were included within

the scope of license renewal. The staff determined that the applicant's approach to scoping

SSCs relied on to demonstrate compliance with the SBO rule (10 CFR 50.63) was consistent

with the staff's April 1, 2002, interim staff guidance.

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

of the license renewal database 10 CFR 54(a)(3) scoping results, reviewed a sample of the

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

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

that the applicant had identified and used pertinent engineering and licensing information in

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i order to determine the SSCs required to be in scope in accordan6e with the 10 CFR 54.4(a)(3)

criteria.;- Based on this sampling review and discussions with the applicant, the audit team

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

scoping criteria of 10 CFR 54(a)(3) was adequate6.

2.1.3.1.2 Plant-Level Scoping'of Systems and Structures'

The applicant documented its methodology for performing the scoping 'of SSCs in accordance

with 10 CFR 54.4(a) in implementation'procedures SP-LR-2-2 and SP-LR-2-4. 'The applicant's

approach to system and structure scoping was consistent with the methodology described in

Section 2.1.3 of the LRA. Specifically, SP-LR-2-2 specified that the personnel performing

license renewal scoping use CLB documents-and list-all functions that the-system or structure is

required to accomplish. 'Sources of information regarding the CLB for systems included the

FSAR, functional system descriptions, total plant numbering system (TPNS) database,

Maintenance Rule information, operations lesson plans, plant drawings, PRA'model, the SER,

and docketed correspondence. The applicant~then compared identified system ,or'structure

functions to a list of scoping screening questions to determine whether the functions met the

scoping criteria of 10 CFR 54.4(a).

The applicant documented the results of the plant-level scoping process in accordance with

Appendix A, uDatabase Scoping Instructions," to'SP-LR-2-2. The database scoping form

included a description of the structure or system,-a listing of functions performed by the' system

or structure, information pertaining to system realignment (as applicable), identification of

intended functions (defined as final functions), the 10 CFR 54.4(a) scoping criteria met by the

system or structure, references, and the basis'for the classification of the system or structure

intended functions. During the'scoping methodology audit, the staff reviewed a sampling of

scoping reports and concluded that the applicant's'scoping forms contained an appropriate

level of detail to document the scoping process.

Conclusion

Based on a review of the LRA, the scoping and s6reening 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 was adequate.

in particular, the staff determined that the applicant's methodology reasonably identified

systems and structures within the scope of license renewal and their'associated intended

functions.

2.1.3.1.3 Component-Level Scoping

After th6 applicant had identified systems and stnuctures within the scope of license renewal

and their associated intended functions, a review was performed to identify the components of

each in-scope system and structure that sipported an intended function.' As described in

Section 2.1;4 of the LRA, a component was considered to be in scope if it was determined that

the component was'needed to fulfill a system intended function.

Mechanical Component Scoping

Section 6.0, uBoundary Procedure," of SP-LR-2-4 provided the applicant's proceduralized

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-J

guidance for scoping mechanical system components. The applicant initially generated a listing

of mechanical system components based on information derived from a review of the system

license renewal boundary diagrams to identify system components required to perform a

system intended function. Procedure SP-LR-2-4 discusses in detail how to (1) determine

system boundaries, (2) indicate components within a specific flowpath which are required for

performance of intended functions, and (3) determine and identify system and interdisciplinary

interfaces (e.g., mechanical/structural, mechanical/electrical, structural/electrical). The audit

team reviewed the results of the boundary evaluation and discussed the process further with

the applicant. The team determined that mechanical system evaluation boundaries were

established for each system within the scope of license renewal. These boundaries were

determined by mapping the pressure boundary associated with system-level license renewal

intended functions onto the system process and instrumentation diagrams (P&lDs). System

components meeting the criteria of 10 CFR 54.4(a) were classified as within the scope of

license renewal. Mechanical component types were loaded into a scoping and screening

database and further review was performed to ensure all component types were identified. A

preparer and an independent reviewer performed a comprehensive evaluation of the boundary

drawings to ensure the completeness and accuracy of the review results.

The NRC audit team conducted detailed discussions with the applicant's license renewal project

management personnel and reviewed documentation pertinent to the scoping process. The

team assessed whether the applicant had appropriately applied the scoping methodology

outlined in the LRA and implementation procedures and whether the scoping results were

consistent with CLB requirements.

The audit team reviewed the process of scoping for several mechanical systems. Those

systems included the residual heat removal/low head safety injection, AFW, main steam, and

open-cycle cooling water systems. The audit team determined that the applicant had identified

and highlighted system P&lDs to develop the system boundaries in accordance with the

procedural guidance. The applicant was knowledgeable about the process and conventions for

establishing boundaries as defined in the license renewal implementation procedures.

Additionally, the team determined that the applicant had independently verified the results in

accordance with the governing procedures. Specifically, other personnel knowledgeable about

the system had independently reviewed the marked-up drawings to ensure accurate

identification of system intended functions. The audit team performed additional crossdiscipline verification and independent reviews of the resultant highlighted drawings before final

approval of the scoping effort.

Conclusion

The staff determined that the applicant's proceduralized methodology was consistent with the

description provided in Section 2.1.4 of the LRA and the guidance contained in NUREG-1 800,

Section 2.1, and was adequately implemented. On the basis of the applicant's detailed scoping

implementation 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 met the requirements of 10 CFR 54.4(a).

Structural Component Scoping

The licensee performed its structural scoping in accordance with the detailed methodology

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defined in'SP-LR 2-2, "Plant Farley Scoping- Procedure." The scoping procedure is used to

evaluate SSCs to identify their functions and determine which funrciions are intended functions

required for compliance with one or more criteria of 10 CFR 54.4(a)(1 -3). The applicant

identified the structural component intended functions for in-scope SCs based on the guidance

provided in NEI 95-10. The procedure also described the source design documentation to be

used for the evaluation of structures meeting the 10 CFR 54.4(a)(1-3) criteria. For civil

structures, the evaluation boundaries were'determined by developing a complete description of

each structure. This was accomplished by reviewing design drawings, the FSAR, DBDs, and

selected plant walkdowns. The applicant created a Microsoft Access database for use in

compiling the scoping results. The four primary forms contained in the database identify

potential functions, final functions, system, and function scoping.

The applicant then identified systems and structures that perforrmi each intended function. For

10 CFR 54.4(a)(2) civil SSCs in proximity to SR civil, mechanical, or electrical SSCs, the

applicant used a spaces approach to scope SSCs inside SR structures. As an example, all

supports in a -eismic Category I building are in' scope whether or not they are seismicCategory I, Il/I, or 11 in'design. The applicant considered multiple intended functions for SCs

consistent with the staff guidance provided in Table 2.1-3 of NUREG-1800.

For each in-scope structure, the applicant documented a list of the structural components within

the evaluation boundaries' for the system, identified the component intended functions for the

structural components, and identified the applicable design or licensing basis references used

to make the determinations. Tables 2.2-1a through 2.2-1f of the LRA provide'a complete plantspecific list of FNP systems and structures within the scope of license renewal.

The applicant used license renewal boundary procedure SP-LR-2-4 to define the evaluation

boundaries for civil systemrand structure'functions determined to be in the scope of license

renewal during performance of FNP scoping procedure SP-LR-2-2. 'The team reviewed license

renewal civil boundary drawing' D-170084L, sheet 1, dated August 15, 2003, which shows

overall structures (highlighted in red) that contain areas with in-scope structural SSCs. The

entire structure associated with an intended function will normally be included in'the scope of

license renewal. Boundary form SP-LR 2-4, which is'part of the FNP electronic database, is

then used to identify the TPNS associated with the boundary form. Three people, one in the

civil group, one in the mechanical group, and one in the electrical group, verified the civil

boundary forms.

The NRC audit team conducted detailed discussions with the applicant's license renewal project

management personnel and reviewed docu'rentati6n pertinent to the scoping process. The

team assessed whetherthe applicant had appropriately applied the scoping methodology

outlined in the LRA and implementation procedures and whether the scoping results were

consistent with CLB requirements. The team 'also reviewed scoping reports for the auxiliary

building, containment, and'yard structures. inrgeneral, the team determined that the applicant's

overall approach to license renewal structural scoping appeared to be adequate.

The audit team reviewed the screening procedure, 'discussed the structural scoping

methodology with the applicant's cognizarit eriginee-rs,' and reviewed several plant structural

drawings to verify proper implementation of the scoping process for structural components.

The team also compared a sample of structural components identified in'the drawings to the

structural list in the license renewal database to ensure consistency. Based on these audit

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activities, the team did not identify any discrepancies between the methodology documented

and the implementation results.

Conclusion

The staff determined that the applicant's proceduralized methodology was consistent with the

description provided in Section 2.1.4 of the LRA and the guidance contained in NUREG-i 800,

Section 2.1. Based on a 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 concluded that the applicant's methodology for identifying structural

components within the scope of license renewal met 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 NUREG-1 800 states

that an applicant may use the plant spaces approach 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.

Table 2.5-1, "Examples of 'Plant Spaces' Approach for Electrical and l&C Scoping and

Corresponding Review Procedures," of NUREG-1800 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, 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.

The staff reviewed FNP procedure SP-LR-2-5, "License Renewal Plant Farley Screening

Procedure," and determined that it provided adequate guidance to the engineers performing

l&C reviews. The procedure describes the process to identify the component types that will be

subject to AMR and the long-lived, passive component types determined to be within the scope

of the license renewal rule. To implement the spaces approach for aging management

discussed in Section 4.2.1.1 of NEI 95-10, Revision 3, the applicant based the boundary

determination for electrical components on plant location. In the spaces approach, FNP

segregated the plant into areas where common bounding environmental parameters can be

assigned. The staff reviewed FNP procedure SP-LR-2-4, "License Renewal Plant Farley

Boundary Procedure," Version 2.0, and determined that it provided adequate guidance to define

evaluation boundaries for electrical functions that should be in the scope of the LRA. The

FNP's LRA engineers created a boundary to encompass all electrical components and called

the boundary "EC." The applicant established a pseudo system, which it named R99 for the

electrical screening process, and documented the results in a boundary form. The staff

observed that the applicant had identified all electrical/l&C component types used plantwide,

regardless of the system, within the boundary. In the form, the applicant identified the

boundary as electrical components (EC) and listed the buildings and structures that are

included in the boundary. The applicant also discussed in the form the screening of the

components credited in the CLB with supporting the regulated events. The form listed the

names of all the systems and the TPNSs that are within the boundary and referenced the

drawings from which information was collected. The staff observed that the form identified the

names of the preparer and mechanical and electrical verifiers.

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The applicant also conducted a search of plant docubrients, controlled drawings, the plant

equipment database, and interface with the parallel mechanical and civil/structural screening

efforts to identify'all components required to' p rform license renewal intended functions. For

example, the applicant noted that during the reviewit found local control panels of in-scope

equipment on drawings but not 'discussed'in'the'FSAR. The applicant then evaluated those

panels to see if they met th6 scoping criteria. ''':-

The audit team reviewed the' electrical boundarry procedure, discussed the electrical scoping

methodology with the applicant's cognizant enginfeers, and reviewed several plant electrical

packages to verify proper im plemnentation of the scoping process for electrical components.

The team also comrmpared a sample of electrical components identified in the documentation to

the electrical commodity list' in thelicensed rene'wal database to ensure consistency. Based on

these audit activities, the team did not identify-any discrepancies between the methodology

documented and the irnpleriientation results.' :-

Conclusion -

The staff determined that the applicant's proceduralized methodology was'consistent with the'

description provided in Section 2.1.4 'of thd LRA and the guidance contained in NUREG-1 800,

Section 2.1. Based on' a review' of inf6rmatibh'6ontained in the LRA, the applicant's detailed

scoping iftiplementatio6 procedures, and a Sampling review of electrical commodity scoping

results, the staff concluded that the applicant'sImethodology for identifying electrical -

commodities 'within the scope of license renewal met the requirements of 10 CFR 54.4(a).-

2.1.3.2 Screening Methodology

The staff reviewed the screening methodology used by the applicant to determine if

mechanical, structural, and electrical components within the scope of license renewal would be

subject to further aging management evaluation.2 The applicant described its screening process

in Section 2.1.4 of the LRA: In general, the'applicant's screening approach consisted of

evaluations to determine which in-scope 'structures and components were passive and longlived. Passive, long-lived structures and components were then subject to further AMR.

The staff evaluated the applicant's screening' methodology against the criteria contained in

10 CFR 54.21 (a)(1-2) using the review guidance contained in NUREG-1 800, Section 2.1.3.2,

"Screening." According to 10 CFR 54.21 (a)(1), the applicant's IPA must identify and list those

structures and components subject to an AMR. Further, 10 CFR 54.21 (a)(1) requires that

structures and components subject to an AMR shall encompass those structures and

components that (1) perfo'rm'an' intended function, as'described in 1 O'CFR '54.4, without

moving' parts'or a change in configuratioWn' o-r prop-'rties, and (2) are not subject to replacement'

based on a qualified life br specified time period. Per 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 were unique to-the mechanical,

structural, and electrical disciplines. The following sections describe the staff evaluation of the

applicant's screening approach'for 'each of these'disciplines.-

2.1.3.2:1 Mechanical Component Screening'

The team r'eviewed the methodology used by the applicant to determine if mechanical

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I

components within the scope of license renewal would be subject to further AMR. For

mechanical components, the applicant first established evaluation boundaries for the various

plant mechanical systems, as described in Section 2.1.3.1.3 of this SER. The applicant then

applied a screening process to each mechanical system in order to determine the types of

mechanical components and commodities within the systems which are subject to an AMR, and

the various materials and environments to be considered in the AMR.

The listing of mechanical components was facilitated by combining these items into commodity

groups from a review of each boundary drawing. The applicant placed these commodity groups

into the license renewal database and evaluated them in accordance with the screening criteria

described in SP-LR-2-5. The applicant provided the staff with a detailed discussion of the

process and provided screening report information from the license renewal database that

described the screening methodology, as well as a sample of the screening results reports for a

selected group of SR and NSR systems. The audit team determined that the screening

methodology was consistent with the requirements of the Rule and that implementation of the

methodology is adequate to identify SCs that meet the screening criteria of 10 CFR 54.21 (a)(1).

During the audit, the team reviewed the methodology used by the applicant to identify and list

the mechanical components and commodities subject to an AMR, as well as the applicant's

technical justification for this methodology. The team discussed the methodology and results

with the applicant's cognizant engineers and senior staff. The team also examined the

applicant's results from the implementation of this methodology by reviewing a sample of the

mechanical systems identified as within scope. These systems included the residual heat

removal/low head safety injection, AFW, main steam, and open-cycle cooling water systems.

The review included the evaluation boundaries and resultant in-scope components, the

corresponding component-level intended functions, and the resulting list of mechanical

components and commodity groups subject to an AMR.

The team reviewed several summary screening reports which list a breakdown of the

mechanical components in scope for license renewal. Each report lists several categories

including component type, if an AMR was required, material, and an extensive comment

section. The team also reviewed a sample of the mechanical drawing packages assembled by

the applicant and discussed the process and results with the cognizant engineers who

performed the review. The audit team did not identify any discrepancies between the

methodology documented and the implementation results.

Conclusion

The staff determined that the applicant's mechanical component screening methodology was

consistent with the guidance contained in NUREG-1 800 and was adequate to identify those

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 team reviewed the methodology used by the applicant to determine if structural

components within the scope of license renewal would be subject to further AMR. For civil

structures and component supports, the applicant applied a screening process to buildings and

civil structures determined to be in scope in order to determine the types of structural elements

utilized and the various materials and environments to be considered in the AMR. The

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applicant then established'evaluation boundaries for the various plant structures and structure -

groups within the scope'of liceise renewal: Generally, the boundary for a building or structure

is the entire building including base slabs,' foindations, walls, beams,-slabs, and steel

superstructure. The applicant identified and listed the various types of structural elements,

materials, and environments that make up the buildings and structures. Several structural

drawings,' including screening reports for the auxiliary building, containment, and yard

structures, were reviewed to identify any structural components that were not contained in the

FNP license renewal database. ; - -

The listing of structural elements'was facilitated by combining these items into commodity

groups. 'The applicant developed a list of structural commodity groups and components for

each civilstructural evaluation boundary. -The applicant provided the staff with a detailed..

discussion of 'the process and provided techtinical reports that described the screening

methodology, as well as a'sample of the screening results reports for a selected group of SR.

and NSR systems. *The audit team determined that the screening methodology was consistent

with the requirerents of the Rule and that implementation of the methodology was adequate to

identify SCs that meet the screening criteria of 10 CFR 5421 (a)(1).

During the audit of the applicant's license renewal scoping and screening process, the team

reviewed the imethodology used by the applicant to identify and list the structural components

and structural commrodities-subject to an AMR, as well as the applicant's technical justification

for this methodology. The team discussed the methodology and results with the applicant'scognizant engineers and -senior staff. The team also examined the applicant's results from the

implementation of this methodology by reviewing a sample of the auxiliary building plant

structures identified as being within scope. The review included the evaluation boundaries (civil

boundaries are'structures based) and resultant in-scope components, the corresponding

component-level intended functions, and the resulting list of structural components and

structural commodity groups subject to an AMR.

The team reviewed several summary screening reports which list a breakdown of the structural

components in scope for license renewal. The reports' reviewed by the team included those for

the auxiliary building, containment, and yard structures. Each report lists several categories

including'component type, if an AMR was required, material, and an extensive comment - section. The team also reviewed a'sample of the structural drawing packages assembled by

the applicant and discussed the process and results with the cognizant engineers who

pedormed the review. The'audit team'did not identify any discrepancies between the

methodology documented and the implemn rtati6n 'results.

Conclusion -'- ^ . - r -

The staff determined that the applicant's structural component screening methodology was

consistent with the guidance contained in NUREG-1 800 and was adequate to identify 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 team'reviewed the methodology used by the applicant to determine if electrical

components within the scope of license renewal would be subject to further AMR. For electrical

components, the applicant applied a screening process by identifying electrical commodities

within the facility. The LRA engineers identified all electrical and l&C component types in use at

_ 2-23
FNP based on the listing provided by Appendix B to NEI 95-10, NUREG-1801, and the EPRI

Electrical Handbook and from a review of plant documents, controlled drawings, the plant

equipment database, and interface with the parallel mechanical and civil/structural screening

efforts.

Electrical component types were organized into commodity groups such as breakers, switches,

and cables. The applicant assessed those electrical and l&C components that interface with

other components, such as electrical racks, panels, frames, cabinets, cable trays, conduit, and

their supports in the appropriate mechanical or civil/structural sections. The applicant

considered internal wiring, terminal blocks, and connections located inside a breaker cubicle to

be parts of the breaker and screened the breaker but not the individual internal parts. The

applicant classified components as safety-related if they could prevent or adversely affect a

function that meets the criterion of 10 CFR 54.4(a)(1), rather than nonsafety-related per 10 CFR

54.4(a)(2). Using this methodology, the applicant determined that the electrical component

types that require an AMR are cables, connectors, buswork, oil-static cables, and various

switchyard components. The applicant documented the screening results in the "Summary

Screening Report-EC" for electrical/l&C systems.

The team discussed the methodology and results with the applicant's cognizant engineers and

senior staff. The team also examined the applicant's results from the implementation of this

methodology by reviewing several electrical/l&C commodity samples from the license renewal

database. The review concluded that the applicant's staff had consistently applied the

screening criteria to identify those electrical/l&C commodity groups subject to an AMR. The

audit team determined that the FNP electrical screening process was consistent with criteria in

10 CFR 54.21 (a)(1)(ii) and excluded those components or commodity groups that are subject to

equipment qualification requirements. The team did not identify any discrepancies between the

methodology documented and the implementation results.

The staff also reviewed the applicant's approach to scoping and screening of electrical fuse

holders. In license renewal ISG-5, "Identification and Treatment of Electrical Fuse Holders for

License Renewal," dated March 10, 2003, the staff stated that, consistent with the requirements

specified in 10 CFR 54.4(a), fuse holders (including fuse clips and fuse blocks) are considered

to be passive electrical components. Fuse holders would be scoped, screened, and included in

the AMR in the same manner as terminal blocks and other types of electrical connections that

are currently being treated in the process. This staff position applies only to fuse holders that

are not part of a larger assembly, but support SR and NSR functions in which the failure of a

fuse precludes a safety function from being accomplished (10 CFR Part 54.4(a)(1) and (a)(2)).

As described in Section 2.1.5.5, "Fuse Holders (ISG-05)," of the LRA, fuse holders that were

not part of a larger assembly were identified and included in scope in a manner similar to that

used for terminal blocks. The team determined that this was consistent with the ISG.

Conclusion

The staff determined that the applicant's electrical and l&C screening methodology was

consistent with the guidance contained in NUREG-1 800 and was adequate to identify passive,

long-lived components within the scope of license renewal that are subject to an AMR.

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2.1.4 Conclusion' -

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 formed the basis of the staff's safety determination. The staff

determined 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, was consistent with the requirements

of the Rule and the-staff's position on the treatment of nonsafety-related SSCs. On the basis of

this review, the staff concludes that the applicant's methodology for identifying the SSCs within

the scope of license renewal and the structures and components 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

2.2.1 Introduction

The SOC for the license renewal rule (60 Federal Register (FR) 22478) indicates that an

applicant has the flexibility to determine the set of SSCs for which an AMR is performed. In

LRA Section 2.1, the applicant described the methodology for identifying the SSCs within the

scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to

determine which of the SSCs are required or not required to be included in the scope of license

renewal. The" staff reviewed the plant-level scoping results to determine whether the applicant

had properly identified all plant-level SSCs relied upon to mitigate DBEs, as required by

10 CFR 54.4(a)(1), or whose failure could prevent satisfactory accomplishment of any of the

safety-related functions, as required by 10 CFR 54.4(a)(2), as well as the SSCs relied on in

safety analysis or plant evaluations to perform a function that is required by one of the

regulations referenced in 10 CFR 54.4(a)(3).

The staff reviewed the SSCs that the applicant'did not identify as being within the scope of

license renewal to determine whether they have any intended functions that are within scope.

The staff also'reviewed selected SSCs that the applicant identified as being within the scope of

license renewal to verify that the applicant had properly identified their components within the

evaluation boundary that are subject to an AMR, in-accordance with the requirements of

10 CFR 54.21 (a)(1). To determine whether the applicant identified the SSCs that are'subject to

an AMR, the staff reviewed the components that the applicant did not identify as being subject

to an AMR. '

2.2.2 Summary of Technical Information in the Application

In LRA Tables 2.2-1a through 2.2-1i,'the applicant listed the plant systems and structures and

identified those'that are within the scope of license renewal and those'thit are not within the

scope of license renewal. Based on the DBEs considered in the plant's CLB for the safetyrelated SSCs, the CLB information relatingto nonrsafety-related SSCs,.and certain regulated

events, the applicant identified those plant-level systems and structures within the'scope of

license renewal, as defined in 10 CFR 54.4.

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.1

Tables 2.2.1a through 2.2.1f of the LRA list the systems and structures that the applicant

determined to be within the scope of license renewal, as follows:

* Table 2.2-1a, "Systems and Structures within the Scope of License Renewal-Reactor

Coolant System"

* Table 2.2-1 b, "Systems and Structures within the Scope of License

Renewal-Engineered Safety Features"

* Table 2.2-1 c, "Systems and Structures within the Scope of License Renewal-Auxiliary

Systems"

* Table 2.2-1 d, "Systems and Structures within the Scope of License Renewal-Steam

and Power Conversion Systems"

* Table 2.2-le, "Systems and Structures within the Scope of License

Renewal-Structures and Component Supports"

* Table 2.2-1f, "Systems and Structures within the Scope of License Renewal-Electrical

Components"

Section 2.3 of the LRA describes the mechanical systems listed in Tables 2.2-1 a through

2.2-1 d; Section 2.4 describes the structures listed in Table 2.2-2d and Table 2.2-1 e; and

Section 2.5 describes the electrical and l&C components listed in Table 2.2-1 f. The applicant

identified 37 mechanical systems, 9 structures, and 22 electrical and I&C systems within the

scope of license renewal.

Tables 2.2-1g, 2.2-1h, and 2.2-1i list the mechanical systems, structures, and electrical l&C

systems, respectively, that the applicant determined not to be within the scope of license

renewal. The applicant originally identified 27 mechanical systems, 25 structures, and 27

electrical and l&C systems that are not within the scope of license renewal.

In its response to RAI 2.1-1 (discussed in Section 2.1 of this SER), the applicant changed the

methodology used for determining the portions of non-attached, non-safety-related piping that

are within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). By letter dated

April 16, 2004, the applicant stated the following:

SNC [Southern Nuclear Company] will consider all fluid-bearing NSR [non-safety-related] SSCs to

be in the scope of the criterion of 10 CFR 54.4(a)(2), provided the NSR components are located in

the same space as the SR [safety-related) SSCs. In addition, if the SR SSC is determined to not

be vulnerable to the effects of the spray/leakage, then the NSR SSC would not be in the scope of

the Rule [license renewal] since the NSR SSC could not prevent or adversely affect the SR SSC

from performing its safety related function. The revised methodology will include evaluating the

impact of sprays and leaks on mechanical and structural SR SSCs, as well as electrical SR SSCs,

with no limitations on the duration of the sprays/leaks.

By letter dated June 4, 2004, the applicant submitted the supplemental information associated

with the determination of SSCs within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(2) as a result of the above changed scoping methodology (see

Enclosure 2, "Joseph M. Farley Nuclear Plant Units 1 and 2, Application for License Renewal,

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Supplemental Information Related to 10 CFR 54.4'(a)(2)").

In Enclosure 2 to the letter, the applicant stated that it had broadened the methodology used for

scoping non-attached non-safety-related piping in accordance with 10 CFR 54.4(a)(2) in the

following manner:

* - elimination of any distance criteria for excluding a spatial interaction between safetyrelated and non-safety-related SSCs

* further evaluation of spatial 'interaction effects on mechanical and structural safetyrelated SSCs (i.e.,valid target considerations not limited to electrical SSCs)

The methodology change resulted in a small change in the number of systems within the scope

of license renewal as required by 10 CFR 54.4(a)(2). The applicant added the roof drains and

sanitary drains systems to thescope~of license renewal 'and incorporated them into'the liquid

waste and drains (LW&Ds) system. The methodology change'did not result in any systems

being removed from'scope that had been previously identified as within the scope of license

renewal. Therefore, the number of mechanical'systems not within the scope of license renewal

was reduced to 25 systems. - ' '

The rmethodolo'y change also increased thermechanical SSCs within the'scope of license

renewal for the open-cycle cooling water, closed-cycle cooling water, demineralized water,

potable and sanitary water, reactor makeup'water storage, chemical and volume control,

feedwater,~and the LW&Ds systems. The applicable section for each of these systems

discusses the impact of the 10 CFR 54.4(a)(2) scoping methodology changes on the AMR

results.

2.2.3 Staff Evaluation

In LRA Section 2.1, the applicant described its methodology for identifying the structures and

systems that are within the scope of license renewal and subject to an AMR. The staff

reviewed the scoping and screening methodology and provided its evaluation in Section 2.1 of

this SER. As addressed in the applicant's response to RAI 2.2-1 dated April 16, 2004, the

applicant changed the methodology used for scoping non-attached non-safety-related piping in

accordance with 10 CFR 54.4(a)(2). To verify thatfthe applicant properly implemented its

methodology, the staff focused its review onthe'implementation results as shown in LRA

Tables 2.2-1 a thtrough 2.2-i ito confirm that the applicant omitted no plant-level systems and

structures within the sc6oe of license renewal. ' - -

The staff determined whether the applicant properly identified the structures and systems within

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected

structures and systems that the applicant identified as not falling within the scope of license

renrewal to'verify whether they have' any intended functions that do fall within the scope of -V

license renewal.- The staff conducted its review of the "applicant's implementation in accordance

with the guidance described in Section 2.2,-"Plant Level Scoping Results," of the SRP-LR

(NUREG-1 800).

The staff sampled the contents of the FSAR based on the listing of systems and structures in

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I

LRA Tables 2.2-1 g through 2.2-1 i to determine whether any systems or structures that may

have intended functions as defined by 10 CFR 54.4 were not included within the scope of

license renewal.

In reviewing LRA Section 2.2, the staff identified areas in which it needed additional information

to complete the evaluation of the applicant's plant-level scoping results. Therefore, by letter to

the applicant dated December 12, 2003, the staff issued RAI 2.2-1, RAI 2.2-2, RAI 2.2-3, and

RAI 2.2-4 and, by letter dated March 23, 2004, the staff issued RAI 2.2-5, concerning the

specific issues related to whether the applicant had properly applied the scoping criteria of

10 CFR 54.4 and the screening criteria of 10 CFR 54.21(a)(1). The following paragraphs

describe the staff's RAIs and the applicant's responses.

RAI 2.2-1

In a comparison of the FNP units, the staff found that the FNP LRA did not identify the design

differences in the systems and components between FNP Unit 1 and Unit 2. Section 1.1.2 of

the FNP FSAR states that "the two units are essentially the same, and the descriptions of one

unit are interpreted as applying to both units. Differences between the two units, and

particularly structures, systems, and components which are shared between the two units, are

specifically pointed out." Section 1.2.2 of the FSAR lists the systems, spaces, and equipment

shared by the two units. A preliminary comparison of the Unit 1 and Unit 2 license renewal

boundary drawings for certain systems indicated that corresponding components considered

within the scope of license renewal for one unit were considered out of scope for the other unit.

As an example, the primary temperature elements (TEs) 22931 and 2293J were considered

within scope on license renewal boundary drawing D-175007L (Unit 1) but out of scope on

license renewal boundary drawing D-205007L (Unit 2).

The staff requested that the applicant describe the design differences between the systems and

components, together with the associated CLBs for Units 1 and 2, and explain how it has

addressed these differences in the scoping and screening review process for the corresponding

systems of the two units.

ApDlicant's Response and Staff's Evaluation

By letter dated January 9, 2004, the applicant responded that there is no difference between

TEs 22931 and 2293J of the two units. The loop 2293 TEs are strap-on devices for both units

and do not penetrate the pressure boundary of the auxiliary feedwater system piping. The TEs

are electrical components. Therefore, their scoping review was performed as part of the

electrical component evaluation described in LRA Section 2.5.1. As such, TE-2293A through

TE-2293L should not have been highlighted on the Unit 1 license renewal boundary drawing

D-1 75007L.

With regard to how the applicant addressed design differences between Unit 1 and 2 systems

and components and the associated CLBs in the scoping and review process, Section 2.1 of

the LRA describes the applicant's methodology. The applicant stated that a primary source of

information used in scoping was the FSAR.

Section 1.1.2 of the FSAR states that the two units are essentially the same, and germane

differences between the two units are identified. Section 1.2.2 of the FSAR also provides a

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summary listing of the spaces and equipmentshiared by the two units. In its response, the

applicant also identified and listed the system functional differences thatfapply to one unit and

not to the other and pointed out the additional unit differences identified on the license renewal

boundary drawings.

Based on its review, the staff finds thedapplicant's response to RAI 2.2-1 acceptable, with

regard to describing the Unit 1 and Unit 2 design differences because it adequately identifies

LRA and FSAR sections that address these differences and how the applicant dealt with them

in the scoping and screening review process. The applicant also adequately identified the two

units' system-level functional differences and the differences between the two units that are

shown on the license renewal boundary'drawings '>Th'erefore, the staff considers RAI 2.2-1

resolved.

RAI 2.2-2

According to the legend for license re'new'a boundary drawing D-506450L; components within

the scope of license' reniewal are highlighted in red.' A comparison of component types -subject

to an AMR (listed in LRA Section 2 tables) with thos6 highlighted on the license reneWal

boundary drawings shows that ma'ny of the components highlighted inred (i.e., pressure

instrumentation) are not subject to an AMR; that is, these components were screened out. The

LRA does not provide another means of identifying the specific components within the

component types (or groups) subject to an AMR. Such an identification would have provided

the end results of the scoping and screening review process. The staff needs this information

to determine whether the specific components'(which make up the component types) are'

properly identified as subject to an' AMR, ini accordance with the requirements of

10 CFR 54.21(a)(1).

The'staff requested that the applicant provide documentation, in the form of either tables or

additional drawings, to identify the specific cbmponents (constituting the component types) that

are within the scope of license renewal and subject to an AMR.

Applicant's Response and Staff's Evaluation

By letter dated January 9, 2004, the applicantfreferenced LRA Section 2.1.4 in stating that

component types used in the FNP IPA include the use of comIrn6dity groups where appropriate,

and that the commodity groups utilized are sirilar to those presented in NEI 95-10, Revision 3,

and Table 2.1-5 of NUREG-1800, and those 'used by previous applicants.

The applicant further stated that '1 0 CFR 5421 (a)(1) requires the LRA to identify only those

systems, structures, and components subjectto an AMR for those SSCs within the scope of

license renewal. In addition,' NUREG-1800 and R6gulat6ry Guide (RG) 1.188 accept the use of

commodity groups for presenting this information. There is no requirement, nor is it necessary

in the sco'ping and screening process, to list the spcifi&6orponents that the component types

for each'system comprise. The LRA'scoping section'for each'systerripresents'the component

types'for a given system or structure subject to'arn-AMR in tabular form:

In response to the staff's request to identify the specific components within the component

types subject to an AMR, the applicant provided tables which list the component types with

examples of the components/items that make up each component type, the determination of

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I

whether the component type is passive and long-lived, and the determination of whether the

component type is subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.2-2 acceptable because it

adequately identifies the component types used in the FNP IPA and components/items that

make up those component types. Therefore, the staff considers the concerns described in RAI

2.2-2 resolved.

RAI 2.2-3

In the FNP LRA, systems are identified by LRA system name. Table 2.2-1 and license renewal

boundary drawing D-506450L identify the LRA systems. The LRA systems (which use the LRA

system nomenclature) may contain all or part of several FNP systems (which use the traditional

FNP nomenclature). On page 2.2-1 of the FNP LRA, the applicant stated that it made this

change in nomenclature for ease of review and comparison to NUREG-1 801, the GALL Report.

However, this nomenclature change created difficulty for the staff in its review of the scoping

and screening results, because the FNP FSAR and other CLB documentation refer to systems

by the traditional nomenclature. In addition, P&lDs, pipe runs, and components shown on

license renewal boundary drawings are labeled using a three- to six-letter abbreviation (system

code) based on their traditional system designation.

The staff requested that the applicant provide a complete listing of the traditional nomenclature

of FNP systems for both in-scope and out-of-scope systems and system codes used as piping

and component identifiers. The staff requested this list so that it could identify which FNP

system, if any, is evaluated for the purpose of license renewal.

Applicant's Response and Staff's Evaluation

By letter dated January 9, 2004, the applicant responded that SNC chose to package LRA

systems in the GALL format using the GALL license renewal system nomenclature as

applicable to FNP. For each LRA system, LRA Section 2.2 identifies traditional systems or

portions of the traditional systems utilized in the FSAR and other CLB documents.

The applicant stated that the system codes used on the component and pipe run identifiers are

based on FNP's total plant numbering system (TPNS). Individual plant systems receive an

alphanumeric TPNS designator, and individual components within the system are identified with

this designator plus other component-specific coding.

In response to the staff's request for a complete listing of the system codes used as piping and

component identifiers, SNC provided FNP drawing D-177558, "Total Plant Numbering System,"

which shows the system codes used on the component and pipe run identifiers.

Based on its review, the staff finds the applicant's response to RAI 2.2-3 acceptable because it

provides the drawing which shows the complete system codes used as piping and component

identifiers. This information allows the staff to verify which FNP system is evaluated for the

purpose of license renewal. Therefore, the staff considers RAI 2.2-3 resolved.

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RAI 2.2-4

License renewal boundary drawing D-506447L identifies by room number the locations where

safety-related components that have a potential for'damage from a spatial interaction are

located for each system. Note 3 of this license renewal boundary drawing states that the

systems and rooms as identified contain nonsafety-related components which may be in the

proximity of safety-related components.

The staff requested that the applicant provide drawings or descriptive information identifying the

rooms by room number. The staff stated that it needs this information to identify the safetyrelated systems that contain safety-related cbomponents which may be adversely impacted by

failure of non-safety-related components (brought into the scope of license renewal in

accordance with the requirements of 10 CFR 54.4(a)(2)).

Applicant's Response and Staff's Evaluation

By letter dated January 9, 2004, the applicant clarified that the safety-related SSCs that could

be adversely impacted by an age-related'failure of nearby non-safety-related SSCs are

electrically powered from safety-related power sources. The applicant, in its response to the

staff's requests in RAI 2.2-4, provided tables that include room numbers, a room description,

FNP system'of safety-related SSC, safety-related SSC (target) number, and the safety-related

SSC (target) description.

Based on its review, the staff finds the applicant's response to RAI 2.2-4 acceptable because it

adequately provides the information required to identify the safety-related systems containing

safety-related components which may be adversely impacted by the failure of non-safetyrelated components. Therefore, the staff considers the concerns described in RAI 2.2-4

resolved.

RAI 2.2-5

By letter dated March 23, 2004, the staff requested that the applicant clarify how the FNP LRA

addresses the components listed below. The license renewal boundary drawings show these

components as within the scope of license renewal. These components serve the intended

function of pressure boundary and are passive and long-lived. However, the LRA tables (e.g.,

Table 2.3.3.5 for open-cycle cooling water system) as component types subject to an AMR do

not list them. The staff requested that the applicant justify the exclusion of the following

components from an AMR,'in accordance with the requirements of 10 CFR 54.21 (a)(1):

(a) flexible hoses/connections and flexible joints shown at multiple locations in the opencycle cooling water, closed-cycle cooling water, and emergency diesel generator (EDG)

systems

(b) nitrogen cylinders and air tanks shown on several license renewal boundary drawings

If the nitrogen'cylinders are excluded from an AMR because they are subject to replacement as

defined in 10 CFR 54.21 (a)(1 )(ii), the staff requested that the applicant describe the schedule

for periodic replacement or the monitoring program and the criteria for replacement if they are

replaced on'condition. :

2-31
Applicant's Response and Staff's Evaluation

(a) By letter dated April 22, 2004, the applicant responded that flexible hoses/connections

and flexible joints serve the intended function of pressure boundary and are within the

scope of license renewal. The flexible hoses/connections and flexible joints in the opencycle cooling water and closed-cycle cooling water systems are metallic and are

encompassed by the component type "piping" in LRA Table 2.3.3.5 for open-cycle

cooling water system and in LRA Table 2.3.3.6 for the closed-cycle cooling water

system as subject to an AMR.

The applicant also stated that for the EDG system, the flexible hoses/connections and

flexible joints are constructed of elastomers and are within the scope of license renewal

but were omitted from the LRA. The applicant concurred that it should have included

the component type "flexible connectors" in LRA Table 2.3.3.15 as subject to an AMR

with the intended function of pressure boundary. Correspondingly, LRA Table 3.3.2-15

should have included the AMR results.

After reviewing the applicant's response, the staff concluded that the response did not

provide sufficient information to resolve the staff's concerns. During a telephone

conference on May 24, 2004, between SNC and NRC staff, the staff requested that the

applicant clarify how similar components are grouped under a component type in the

LRA.

By letter dated June 10, 2004, the applicant, in its revised response, stated that flexible

hoses/connections and flexible joints in the open-cycle cooling water and closed-cycle

cooling water systems are made of carbon and stainless steel, are in scope, and are

encompassed by the component type "piping." These components are constructed of

the same materials as piping, exposed to the same internal and external environments,

experience the same aging affects, and are managed for aging by the same programs.

The component type "piping" is included in LRA Table 2.3.3.5 for the open-cycle cooling

water system and LRA Table 2.3.3.6 for the closed-cycle cooling water system with the

intended function of pressure boundary. The component type "piping" is also included in

LRA Table 3.3.2-5 for the open-cycle cooling water system and LRA Table 3.3.2-6 for

the closed-cycle cooling water system. Materials of construction include both carbon

steel and stainless steel.

For the EDG system, the applicant explained that the component type "ducts and

fittings" includes the stainless steel expansion joints in the intake/exhaust subsystem of

the EDG system. The other flexible hoses/connections and flexible joints in the EDG

system are constructed of elastomers and are within the scope of license renewal but

were omitted from the LRA. Therefore, the applicant concurred that it should have

included the component type "flexible connectors" in LRA Table 2.3.3.15 and,

accordingly, LRA Table 3.3.2-15 should have included the elastomer flexible connectors.

Based on its review, the staff finds the applicant's response to RAI 2.2-5a acceptable

because the response clarifies that metallic flexible hoses/connections and flexible joints

in the open-cycle cooling water and closed-cycle cooling water systems are

encompassed by the component type "piping," agrees that the EDG system flexible

hoses/connections and flexible joints should be within the scope of license renewal and

2-32
subject to an AMR, and clarifies that the stainless steel expansion joints in the

intake/exhaust subsystemi of the EDG system are included in the uducts and fittings"

component type and are within the sc6pe of license renewal and subject to an AMR.

Therefore, the staff considers the concerns described in RAI 2.2-5 resolved.

(b) By letter dated April 22, 2004, the applicant responded that the nitrogen cylinders or

bottles are in scope to provide a backup source of pneumatic pressure and are shortlived, as they are subject to replacement based on a qualified life, a specified time

period, or because of condition (10 CFR 54.21 (a)(1)(ii)). The nitrogen cylinder pressure

is monitored daily (every 4 and 8 hours), and, if the pressure has decayed below a

specified value, the cylinder is replaced.

For the air tanks that provide a reserve air capacity, the applicant stated that the air

tanks within'the scope of license renewal are used in various applications and listed in

the LRA tables under several component types. In the compressed air and EDG LRA

systems (Tables 2.3.3.7 and 2.3.3.15), the-component types "air accumulators" and "air

receiver" address various air tanks that provide a reserve air capacity for system-level

use. -The component type "piping" includes some in-line air tanks (because of similarity

to piping and'other in-line fittings and components) as subject to an AMR.

For the air tanks supplied with the valve operators, the applicant stated that pneumatic

valve operators can include air reservoirs or air tanks that are (typically) supplied by the

valve vendor and mounted on the valve as part of the valve operator assembly. These

air tanks are an integral part of the valve operator, directly.support the active function of

the operator,' and are included as part of the valve operator component for license

renewal. The valve operator performs only an active function and therefore is not

subject to an AMR. Age-related degradation of the valve operator is managed under the

requirements'of the Maintenance Rule.

After reviewing the applicant's response to RAI 2.2-5b, the staff found the applicant's

response for the nitrogen cylinders acceptable, since the response explained that the

nitrogen'cylinder pressure is monitored daily and the cylinders are replaced if the

pressure decays below a specified value. Therefore, these cylinders are short-lived and

excluded from being subject to an AMR in accordance with the requirements of

10 CFR 54.21 (a)(1).

For the air tanks that provide a reserve air.capacity, the staff requested, during a

telephone conference between the applicant and the NRC staff on May 24, 2004, that

the applicant clarify how it groups air tanks under the component type 'piping." The

applicant responded that it groups components similar to the pipes that are constructed

of the same materials, exposed to the same internal and external environments,-

experience the s'ame aging affects, and age managed by.the same programs under the

"piping" component type. Based on this discussion, the staff found its concerns for the

air tanks that are provided as a reserve air capacity resolved, since the applicant

explained its approach to grouping air tanks under the component type "piping."

For the pneumatic valve operator air tanks, during a telephone conference between the

applicant and the NRC staff on May 24,2004, the staff agreed to consolidate RAI

2.3.3.5-la and b, RAI 2.3.4.1-1,-and portions of RAI 2.2-5b for the pneumatic valve

2-33
operator air tanks into a revised RAI 2.2-5b, since the applicant's responses to these

RAls were all related to the integral parts of valve operators. Therefore, by letter dated

May 25, 2004, the staff issued the revised RAI 2.2-5b (consolidated RAI) as follows.

The applicant, in its responses to RAI 2.2-5b, RAI 2.3.3.5-1a and b, and RAI 2.3.4.1-1,

stated that air tanks, filters, valves, air reservoirs, and all other components associated

with the control valve operators are integral parts of the valve operator and directly

support the action function of the operator. The staff agrees that valve operators are

active components and are not subject to an AMR. However, the supply air piping and

its associated components (pipes, valve bodies, filters, air tanks, air reservoirs, etc.) are

passive components and are subject to an AMR.

During a telephone conference on May 24, 2004 between the applicant and the NRC

staff, the staff asked the applicant to clarify the following questions about the control

valve operators (as examples) Q1 P1 6V562 on A-1 70059L, Sheet 147; Q2P1 6V560 on

A-200475L, Sheet 47; and HV-3235A/B on D-175033L, Sheet 2:

* The above license renewal boundary drawings show pipes, valve bodies, filters,

air tanks, and air reservoirs as separate components and not as integral parts of

the valve operator. Provide descriptive information or drawings that show the

components that are considered integral parts of the above-mentioned valve

operators.

* If the pressure boundary of an operator-associated component is breeched and

supply pressure is lost, how will the valve operator perform its intended function

of holding the isolation valve at its safe position?

* Is age-related degradation of the components associated with the valve operator

managed under the Maintenance Rule? If so, how is the degradation managed?

By letter dated June 18, 2004, the applicant, in its revised response, stated that

pneumatic actuators, such as diaphragm and piston-type actuators, perform functions

ranging from system isolation (on-off service) to flow or pressure-control type

applications. Valve operators (actuators) are classified as active components per NEI

95-10, Revision 3, and therefore are not subject to an AMR. Accessories (subparts)

commonly found in actuators include positioners, pressure controllers, volume and

pressure boosters, filters, regulators, and solenoid valves. The operators including their

subcomponents are maintained, tested, calibrated, etc., as required to assure the

proper functioning of the control valve as a unit.

The applicant further explained that the normal compressed air systems are non-safety

related, and therefore, the pneumatic actuators are designed fail-safe. Failure position

on a loss of air is to the required DBE mitigation position. For pneumatic actuators that

must remain functional during a DBE, a backup (emergency) compressed gas supply is

provided and included in the scope of license renewal as follows:

* The nitrogen cylinders that provide compressed gas to the pressurizer poweroperated relief valves are included in the scope of the compressed air system.

The nitrogen cylinders are short-lived and therefore not subject to an AMR in

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

* The air accumulator tanks that provide backup supply air to the spent fuel pool

(SFP) exhaust ventilation to penetration room filtration' (PRF) dampers are

included in the scope of the compressed 'air system. The tanks are subject to an

AMR and included in the corponenti type "air accumulatdrs" in LRA Table

The backup supply air to the'main steam system'atmospheric relief valves is

provided by the emergency air compressors and is included in the scope of the

compressed air system.' The pOis'sive' components of the' emergency aircompressor supply (e.g., piping and valve bodies) are subject to an AMR and

included in the component types in LRA Table 2.3.3.7. The air compressors are

active and therefore are' not subject to an AMR. - l -

The backup supply to' the turbine-driven'AFW pump 'steam admission valves

(QN1 2HV3235A and B) is provided by the enmergency air compressor system. In

addition to the backup air supply from the emergency air compressors, each

valve is equipped with an6air reservoir 'with sufficient capacity to open the valves

ard allow pump opeiation for 2 hou6rs' 'These air reservoirs were originally

furnished with the valve and actuator and therefore were treated as integral parts

of the valve operatos for the LRAk'"n response to this'RAI, the applicant

determined that the in-scope components upstream 6f solenoid valves SV-;:'

3235A'and B (license renewal boundary drawings D-1 75033L 'and D-205033L),

which include the air reservoirs, should have been included in the compressed

air system boundary as part of the backup air supply. The passive'components

'-of the backup'air supply (e.g:, 'piping;, valve bodies, and the air reservoirs) are'

subject to an AMR and ire'already iiclWded in the component types'in LRA

'Table 2.3.3.7. The air reservoirs are included in the component type "air

accumulators." The air compressors are active and therefore not subject to an

AMR.~'

In regard to the air reservoirs associated with the main steam isolation valves (MSIVs), which were referred to'in RAI 2.3.4.1-1, the applicant stated that the MSIV is within the

scope of licerise renewal because it isolates steamflow on a signal initiated by the

engineered safety'feature (ESF) actuation system.' An air reservoir is provided for each

MSIV that allows it to remaini open upon'loss of instrument'air. IHowever,'keeping the

MSIV open is not an intended function within the scope of license renewal. These air

reservoirs support this active function of thavalve'operator and are included in the

scope of license renewal as part of the valve operator component. Regardless of

whether considered part of the actuator or a separate component, the air reservoir and

o6therhighlighted cornponents do 'not perfomrn y component intended function for

license renewal since loss of air supplpypressure (e.g.,' loss'of 'pressure boundary

integrity) will close the MSIV which is its required safety position. Maintenance Rule

performance criteria a're^established 'for the'MSIV closure and open flowpath functions.

For the control valves 01 P1 6V562 and Q2P1 6V560, the applicant stated that these

'valves fail to the safe position on lossof the'comrpressed air system air supply.

Therefore, the control valve' air supplies up to the operator interface are not within the

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I

scope of license renewal. Since these valves are fail-safe and are not required to be

repositioned during any DBE, the valve operator will perform its intended function if

supply pressure is lost or the pressure boundary of an operator-associated component

is breeched. For control valve Ql P16V56, pressure controller Ql P16PC562, and

unlabeled air tanks, cushion regulator, equalizing valves, check valve, pressure

indicators, and pressure regulators are considered as integral parts of the valve operator

and are highlighted as within scope. For control valve Q2P16V560 filter N2P16F560;

pressure indicators N2P16PI560A, B, and C; equalizing valve N2P16V560A; and

unlabeled air tanks, check valve, and pressure regulators are considered as integral

parts of the valve operator and are highlighted as within scope. Additionally, instrument

air isolation valve N2P19V1 52C should not have been highlighted.

The applicant also added in its response that, since development of the LRA, a singleacting spring return actuator has replaced the double-acting actuator for valves

Q1P16V562 and Q2P16V560. A volume booster has replaced the air tanks for

Ql P16V562, and the air tanks for valve Q2P16V560 are eliminated. These changes do

not impact the LRA tables, but they do affect the boundary drawings.

The staff reviewed the applicant's revised response and finds it acceptable, on the basis that it

adequately identifies the backup air tanks/gas cylinders and other components associated with

the valve operators that are within the scope of license renewal, adequately identifies those air

tanks/gas cylinders that are subject to an AMR, and adequately justifies exclusion of the air

tanks and other components associated with the valve operators from being subject to an AMR,

in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1).

The staff reviewed the applicant's response to RAI 2.1.1 dated April 16, 2004 and its

supplemental information related to 10 CFR 54.4(a)(2), dated June 4, 2004, Enclosure 2,

"Joseph M. Farley Nuclear Plant Units 1 and 2, Application for License Renewal, Supplemental

Information Related to 10 CFR 54.4 (a)(2)." In Enclosure 2, the applicant considered all

fluid-bearing non-safety-related SSCs to be in the scope of the criterion of 10 CFR 54.4(a)(2),

provided the non-safety-related components are located in the same space as the

safety-related SSCs, with the following exceptions:

1. If the safety-related SSC is determined to not be vulnerable to the effects of the

spray/leakage, then the non-safety-related SSC would not be in the scope of the license

renewal since the non-safety-related SSC could not prevent or adversely affect the

safety-related SSC from performing its safety related function.

2. A spray is not postulated for a unpressurized piping system, however a leak is

postulated.

3. For a leak from a non-safety-related SSC, the non-safety-related SSC is not routed

above safety-related SSCs that are vulnerable to a leak.

4. The revised methodology evaluates the impact of sprays and leaks on safety-related

SSCs with no limitations on the duration of sprays or leaks.

5. The applicant relies on the floor drains, floor drain tank, sumps, and associated

pumps as mitigative features to control internal flooding and as a method to detect

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significant leakage resulting from a failed nion-afety-related'SSC.

6. Non-safety-related SSCs in containrfnent'are not evaluated since safety-related SSCs

in containment are already qualified for the most limiting post-accident environments,

including spray and/or steam.

7. If a non-safety-related SSC does not have an aging effect that requires

management, it is excluded from beirig'within the scope of license renewal.

The staff finds the supplermerntal information related to 10'CFR 54A(a)(2) in the June 4, 2004,

Enclosure 2 to be acceptable, on the basis that it adequately identifies all non-safety-related

SSCs that are added to the scope of license renewal because of the changed 10 CFR

54.4(a)(2) scoping methodology. The staff did not identify any omissions related to the changed

scoping methodology, and thus concludes that the applicant has appropriately identified the

structures and systems that are within the scope of license renewal.

2.2.4 Conclusion

The staff reviewed LRA Section 2.2, includirig the' applicant's supplemental information related

to 10 CFR 54.4(a)(2), and the supporting information in the FNP FSAR to determine whether

the applicant identified all structures and systems within the scope of license renewal. As a

result of this review, the staff did not identify any omissions and thus concludes that the

applicant has appropriately identified the structures and systems that are within the scope of

license renewal, in accordance with 10 CFR 54.4. Sections 2.3 through 2.5 of this SER provide

the staff's detailed review of the SSCs that are subject to an AMR.

2.3 System Sconing and Screening Re'sults-Mechanical Systems

This section of the SER documents the staff's 'review of the applicant's scoping and screening

results for mechanical systems. This section discusses the following mechanical systems:

* reactor vessel internals and reactor. coolant system

* engineered safety features

* auxiliary systems

* steam and power conversion systems

As required by 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 license renewal and subject

to an AMR. To verify that the applicant properly implemented the scoping and screening

methodology, the staff focused its review on the impi ementation results. This approach allowed

the staff to confirm that the applicant had not omitted any mechanical system components that

meet the scoping criteria and are subject t an AMR.

Staff Evaluation Methodolo-gy

The staff evaluated the information provided in the LRA in the same manner for all mechanical

systems. The objective of the review was to determine if the applicant had identified the

components and supporting structures for a specific mechanical system that appeared to meet

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.1

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 passive, long-lived components were subject to an AMR, in accordance with

10 CFR 5421 (a)(1).

Scoping. The staff reviewed the applicable LRA section and associated component drawings,

focusing on components that the applicant had not identified as within the scope of license

renewal. The staff reviewed relevant licensing basis documents, including the FSAR, 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 specified all intended functions

delineated under 10 CFR 54.4(a). When omissions were identified, the staff requested

additional information to resolve the discrepancy.

Screening. After completing its review of the scoping results, the staff evaluated the applicant's

screening results. For those SCs with intended functions, the staff sought to determine 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 did not meet either of these criteria, the staff

sought to confirm that these mechanical system components were subject to an AMR, as

required by 10 CFR 54.21 (a)(1). If discrepancies were identified, the staff requested additional

information to resolve them.

2.3.1 Reactor Vessel Internals and Reactor Coolant System

In Section 2.3.1 of the LRA, the applicant identified the SCs of the reactor coolant system

(RCS) that are subject to an AMR for license renewal. The reactor vessel, internals, and RCS

comprise the systems and components designed to contain and support the nuclear fuel,

contain the reactor coolant, and transfer the heat produced in the reactor to the steam and

power conversion systems for production of electricity.

The applicant reviewed the following approved Westinghouse Owners Group (WOG) generic

topical reports as a source of information for determining the SCs that are within the scope of

license renewal:

* WCAP-14574-A, "License Renewal Evaluation: Aging Management Evaluation for

Pressurizers," December 2000

* WCAP-14575-A, "License Renewal Evaluation: Aging Management Evaluation for

Class 1 Piping and Associated Pressure Boundary Components," December 2000

* WCAP 14577-A, Revision 1, "License Renewal Evaluation: Aging Management for

Reactor Internals," October 2000

The applicant described the reactor vessel internals and RCS in the following sections:

* reactor vessel

* reactor vessel internals

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* reactor coolant system`'an'd connected lines

* steam generators

2.3.1.1 Reactor Vessel

2.3.1.1.1 Summary of Technical Information in the Application

In Section' 2.3.1.1 of the LRA, the applicant described the reactor vessel. The reactor vessel

system boundary includes the reactor vessel itself, 'along with portions of associated systems

that effectively'constitute a part of the'reactor coolant pressure boundary. These systems

include'the contr6l rod drive mechanism'r(CRDM)'pressure boundary components'and pressure

boundary components associated with instrumentation, both in-core flux instrumentation and

core-cooling monitoring. The reactor vessel contains the core, core supporting structures,

control rods,'and other parts directly associated with the core. The upper closure head contains

penetrations for CRDMs, thermocouples, reactor vessel level indicating system (RVLIS)

instruments, and a head vent.'

The vessel shell contains inlet and outlet nozzles located-in a horizontal plane just below thereactor vessel flange, but above the top of the core. The bottom head contains penetrations for

connection arid entry of nruclear in-core instrubmnetatidn.' Conduits extend from the nuclear incore instrumentation'penetrations down through'the concrete shield area and up to a thimble

seal table. The conduits and seal table mechanical seals provide the pressure barrier between

the reactor coolant and the containment atmosphere.

Table 2.2-1 a of the LRA identifies the following criteria used by the applicant to determine the

SSCs that are within the scope of license renewal for the reactor vessel:

* safety-related (10 CFR 54.4(a)(1)) * fire protection (10 CFR 54.4(a)(3))

* pressurized thermal shock (10 CFR 54.4(a)(3))

In Table 2.3.1.1 of the LRA, the applicant identified the reactor vessel component types that are

within the scope of license renewal and subject to an AMR, including bottom head torus and

dome; bottom mounted instrumentation (BMI) guide tubes; BMI penetrations; core exit

thermocouple (CET) and heated junction thermocouple (HJTC) closure assemblies; CET and

HJTC assrmbly bolting;, closure-head dome and flange,' closure studs; nuts, and washers; core

support lugs;'CRDM and instrumentation housing penetration nozzles; CRDM housing flange

adapters'; CRDM latch housings and rod travel housings; head vent penetration; intermediate,

and lower shell courses;'leakage-monitoring tube assembly, primary inlet and outlet nozzles

and nozzle support pads, primary nozzle' safe ends; refueling seal ledge; vessel flange; seal

table and fittings; upper (nozzle) shell course, arnd ventilation shroud support ring.

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 and FNP FSAR Sections 5.4; 4.4.5.5,'and 7.5.4. The

staff conducted its review using the evaluation methodology described in Section 2.3 of this

SER, in accordance'with the guidance-described in Section 2.3 of NUREG-1800.

In'its evaluation, 'the 'staff reviewed the FSAR for any functions delineated under -

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l1

10 CFR 54.4(a) that the applicant did not identify as intended functions in the LRA; the staff

then evaluated that the SSCs with such functions will be adequately managed so that the

component intended functions will be maintained consistent with the CLB for the period of

extended operation. The staff next evaluated that the applicant had identified all passive or

long-lived components that are subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

In its review of LRA Section 2.3.1.1, the staff identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated February 13, 2004, the staff issued an RAI to determine whether the

applicant had properly applied the scoping criteria of 10 CFR 54.4 and the screening criteria of

10 CFR 54.21 (a)(1). The following describes the staff's RAls and the applicant's responses,

dated March 12, 2004.

In RAI 2.3.1.1-3, the staff discussed borated water leakage through the pressure boundary in

pressurized-water reactors (PWRs), and the resulting borated-water-induced wastage of carbon

steel, as a potential aging degradation mechanism for the components. Reactor vessel head

lifting lugs are considered to be such components requiring aging management. However, if

the applicant currently covers these components under the Boric Acid Wastage Surveillance

Program, then additional aging management may not be required. It appeared that the subject

components were not discussed in LRA Table 2.3.1.1; therefore, the staff requested the

applicant to verify whether these components are within the surveillance program or to explain

why they are excluded.

In its response to RAI 2.3.1.1-3, dated March 31, 2004, the applicant stated that the reactor

vessel closure head alloy steel lifting lugs are integral to the head and included within the LRA

Table 2.3.1.1 component group "closure head dome and flange" and are within the scope of the

FNP Borated Water Leakage Assessment and Evaluation Program.

Based on the applicant's response that the reactor vessel head lifting lugs are included in the

LRA Table 2.3.1.1 component group "closure head dome and flange," and are within scope of

the FNP Borated Water Leakage Assessment and Evaluation Program, the staff finds the

above response acceptable.

2.3.1.1.3 Conclusion

During its review of 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 reactor

vessel components. The staff concludes that the applicant has adequately identified the

reactor vessel components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the reactor vessel components

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

2.3.1.2 Reactor Vessel Intemals

2.3.1.2.1 Summary of Technical Information in the Application

In Section 2.3.1.2 of the LRA, the applicant described the reactor vessel internals. The reactor

internals consist of the lower core support structure, the upper core support structure, and the

in-core instrumentation support structures. The reactor internals support the core, maintain fuel

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alignment, limit fuel assembly movement,-maintain alignment between fuel assemblies and

CRDMs, direct coolant flow past the fuel elements, direct coolant flow to the pressure vessel

head, provide gamma and neutron shielding, and provide guides for the in-core instrumentation.

The lower core support structure-consists of the core barrel, the core baffle assemblies, the

lower core plate, the neutron shield panels, the lower core support forging, the secondary

support assembly, and associated support columns. The lower core support structure is

supported at its upper flange from a ledge in the reactor vessel, and is restrained at its lower

end by a radial support system attached to the vessel wall. The upper core support structure

consists of the upper support assembly, the upper core plate, support columns, and control rod

guide tube'assemblies. The in-core instrumentation support structures consist of an upper

system to convey and support thermocouples penetrating the vessel through the upper closure

head and a lower system to convey and support'flux thimbles penetrating the vessel through

the bottom head.

The reactor vessel ihternals functions include structural support, flow distribution, and radiation

shielding. The applicant has further defined these functions to align with those described in

WCAP-14577-A, Revision 1.

In Table 2.2-1a of the LRA, the applicant identified the following criteria it used to determine the

SSCs that are within the scope of license renewal for the reactor vessel internals:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* pressurized thermal shock (10 CFR 54.4(a)(3))

Table 2.3.1.2 of the LRA lists the reactor vessel internals component types that are within the

scope of license renewal and subject to an AMR, including baffle and former plates; baffle bolts;

BMI column cruciforms; BMI columns; clevis inserts and fasteners; control rod guide tube

assemblies;'core barrel and core barrel flange; core barrel outlet nozzles; control rod guide tube

(CRGT) support pins; flux thimble tubes; head/reactor pressure vessel (RPV) alignment pins;

head cooling spray nozzles; HJTC probe holder, probe holder extension, and probe holder

shroud assemblies; internals hold down spring; lower core plate and fuel alignment pins; lower

support columns; lower support forging; neutron panels; radial support keys and fasteners;

secondary core support assembly; upper core plate alignment pins; upper core plate and fuel

alignment pins; upper instrimentation conduit and supports; upper support assembly; upper

support column bases; and upper support columns.

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 and FNP FSAR Section 4.2.2. The staff conducted its

review using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff reviewed the FSAR for any functions delineated under

10 CFR 54.4(a) that the applicant had not identified as intended functions in the LRA; the staff

then evaluated that the SSCs with such functions will be adequately managed so that the

component intended functions will be maintained consistent with the CLB for the period of

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._J

extended operation. The staff next evaluated whether the applicant had identified all passive or

long-lived components that are subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

In its review of LRA Section 2.3.1.2, the staff identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated February 13, 2004, the staff issued an RAI to determine whether the

applicant had properly applied the scoping criteria of 10 CFR 54.4 and the screening criteria of

10 CFR 54.21 (a)(1). The following describes the staff's RAls and the applicant's responses,

dated March 12, 2004.

In RAI 2.3.1.2-1, the staff requested the applicant to verify whether the component group

"neutron panels" listed in LRA Table 2.3.1.2 includes a thermal shield, with an intended function

of providing shielding for the safety-related SSCs, such as the reactor vessel and the reactor

vessel internals, from gammas and neutrons. A thermal shield may be relied upon to minimize

irradiation-induced embrittlement of the vessel and/or the internals. If the component exists at

FNP, the staff requested the applicant to clarify whether thermal shields are included with the

"neutron panels" component group or to justify its exclusion from aging management.

In its response to RAI 2.3.1.2-1, the applicant stated that FNP uses a neutron panel shielding

design instead of a 3600 circumferential thermal shield design. The FNP LRA Table 2.3.1.2

component group "neutron panels" represents several neutron panels strategically located at

high-fluence azimuths to reduce the fluence exposure of the FNP reactor vessel beltline

materials. These neutron panels are fastened to the exterior of the core barrel and are

provided in lieu of a thermal shield. The applicant explained that the term "thermal shield" has

typically been used to describe a design that employs a 3600 circumferential shield to reduce

neutron fluence on the reactor vessel beltline materials.

On the basis of the applicant's response that the LRA Table 2.3.1.2 component group "neutron

panels" represents several neutron panels strategically located at high-fluence azimuths to

reduce the fluence exposure of the FNP reactor vessel beltline materials and that this

configuration serves the same purpose as the 3600 circumferential thermal shield, the staff

finds the above response acceptable.

2.3.1.2.3 Conclusion

During its review of 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 the

reactor vessel internals. The staff concludes that the applicant has adequately identified the

reactor vessel internals components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the reactor vessel internals

that are subject to an AMR, as required by 10 CFR 54.21 (a)(1)

2.3.1.3 Reactor Coolant System and Connected Lines

2.3.1.3.1 Summary of Technical Information in the Application

In Section 2.3.1.3 of the LRA, the applicant described the RCS and connected lines, which

consist of the RCS piping components, pressurizer, and reactor coolant pumps (RCPs).

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RCS Piping Components f i ;

The RCS consists of three parallel heat transfer loops. Each loop contains an RCP, steam

generator, and associated piping and valves. 'In addition, the system'includes interconnecting

piping and instrumentation necessary for operational control. All major components are located

in the containment building. 'During operation, the RCS transfers the heat generated in the core

to the steam generators. 'The RCS pressure boundary provides a barrier against the release of

radioactivity generated within the reactor and is designed to ensure a high degree of integrity

throughout the life of the plant.

The RCS system boundary includes all of the ASME Class 1 piping components, the

pressurizer, the RCPs, and ASME Class 1 branch piping connected to the RCS loops. Based

on this convention, the RCS system boundary includes the ASME Class 1 portions of the

emergency core cooling system (ECCS), chemical and volume control system (CVCS), and

sampling system. The system boundary also includes non-ASME Class 1 piping components

directly associated with the RCS boundary. RCS piping includes special components such asthe pressurizer spray scoop, sample connection scoops, and the resistance temperature

detector (RTD) installation bosses and thermowells.

Pressurizer

The RCS pressure is controlled by the pressurizer, where electrical heaters and coolant sprays

maintain the water and steam in equilibrium. Steam can be formed or condensed to minimize

pressure variations caused by contraction or expansion of the reactor coolant. Spring-loaded

safety valves and power-operated relief valves are connected to the pressurizer upper head.

The pressurizer is a vertical, cylindrical vessel with hemispherical top and bottom heads. A

surge line nozzle and removable electric heaters are installed in the bottom head. Spray line

nozzles'and relief and safety valve connections are located in the top head of the pressurizer

vessel. The pressurizer bottom nozzle is connected to a reactor coolant hot leg by means of

the pressurizer surge line.

Reactor Coolant Pumps

Each of the three reactor coolant loops contains a vertically mounted, single-stage, centrifugal

RCP that employs a controlled leakage seal assembly. The RCPs provide the motive force for

circulating the reactor coolant through the reactor core, piping, and steam generators.-

In Table 2.2-1a'of the LRA, the applicant identified the following criteria it used to determine the

SSCs that are within the scope of license renewal for the RCS and connected lines:

* -Safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.31.3 of the LRA, the applicant listed the RCS and connected lines component types

that are within the scope of license renewal and subject to an AMR, including closure bolting,

Class 1; piping, Class I (reactor coolant loop); piping, Class 1 (piping components less than

nominal pipe size (NPS) 4); piping, Class 1 (piping components greater than or equal to

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NPS 4); valve bodies, Class 1; flow orifice/element, Class 1; RCP (pump casing); RCP (main

flange bolts); RCP (main closure flange); RCP (thermal barrier assembly); pressurizer (closure

bolting-manway); pressurizer (heater sheaths); pressurizer (instrument nozzles and heater

well nozzles); pressurizer (manway and cover); pressurizer (nozzle safe ends); pressurizer

(nozzles-surge, spray, safety, relief); pressurizer (shell, upper head, and lower head);

pressurizer (spray head assembly); pressurizer (support skirt and flange); pressurizer (thermal

sleeves-surge and spray nozzles); pressurizer support lugs, closure bolting, non-Class 1;

piping, non-Class 1; and valve bodies, non-Class 1.

The applicant stated that the RCP seals are not listed in the table and are not subject to an

AMR for the following reasons:

* Seal function is active in nature. Rotating seal faces are a part of the RCP rotating

assembly which is an active component.

* The RCP seal package and its constituent components are periodically overhauled. The

seals are inspected and parts are replaced, as required.

* Plant and industry operating experience with RCP seal performance has demonstrated

the effectiveness of these activities. Seal leakoff is closely monitored in the control

room, and abnormal seal flows are alarmed as conditions requiring evaluation and

corrective actions.

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3, FNP FSAR Chapter 5.0, and FNP FSAR Sections

5.5.1 and 5.5.10. The staff conducted its review using the evaluation methodology described in

Section 2.3 of this SER, in accordance with the guidance described in Section 2.3 of NUREG1800.

In its evaluation, the staff reviewed the FSAR for any functions delineated under

10 CFR 54.4(a) that the applicant had not identified as intended functions in the LRA; the staff

then evaluated whether that the SSCs with such functions will be adequately managed so that

the component intended functions will be maintained consistent with the CLB for the period of

extended operation. The staff next evaluated whether the applicant had identified all passive or

long-lived components that are subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

In its review of LRA Section 2.3.1.1, the staff identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated February 13, 2004, the staff issued an RAI to determine whether the

applicant had properly applied the scoping criteria of 10 CFR 54.4 and the screening criteria of

10 CFR 54.21(a)(1). The following describes the staff's RAls and the applicant's responses,

dated March 12, 2004.

In RAI 2.3.1.3-1, the staff requested the applicant to verify whether the component groups

"piping, Class 1 (reactor coolant loop)"; "piping, Class 1 (piping components < NPS 4)"; and

"piping, Class 1 (piping components 2 NPS 4)" listed in LRA Table 2.3.1.3 also include fittings,

which serve as a pressure boundary. In accordance with 10 CFR 54.4(a), the fittings should be

within the scope of license renewal. The staff requested the applicant to justify the exclusion or

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submit an AMR for the stated components.

In response to RAI 2.3.1.3-1, the applicant confirmed that pipe fittings are included within the

component groups 'piping, Class 1 (reactor coolant loop)"; "piping, Class 1 (piping components

< NPS 4)"; and upiping, Class 1 (piping comnp-nnrits•` NPS'4)." The applicant's component

groups are consistent with the guidance of NEI-95'1 0, Revision3. Appendix B to this industry

guideline identifies typical components and cormmodity 'groupings for use in an IPA.- Item 26 to

this appendix covers the category reactor coolant pressure boundary ciomponents and the

component or commodity group "ASME Class 1 piping." This item' is understood to include pipe

fittings.

Based on the applicant's response that pipe fittings are included in component groups "piping,

Class 1 (reactor coolant loop)"; "pipirig, Class 1 (piping components"< NPS 4)"; and "piping,

Class 1 (piping components 2 NPS 4)" and are within' the scope of license renewal, the staff

finds the applicant's response acceptable.

2.3.1.3.3 Conclusion '

During its review of the LRA, license renewal drawings, and licensing basis' information, the'

staff did not identify any omissions or disnrepahcies in' the applicant's scoping results for the

RCS and connected lines: The staff concludes that the applicant has adequately identified the

RCS and connected line 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 RCS and connected

piping components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1)

2.3.1.4 Steam Generators

2.3.1.4.1 Summary of Technical Information in the Application

Each FNP unit includes three steam generators, one in' each reactor coolant loop. The

replacement steam generators at FNP arWestingh6use Model 54F design. The Unit 1 steam

generators were installed in May of 2000. The Unit 2 replacement steam generators were

installed in May of 2001. All steam generators are vertical U-tube evaporators with integral

moisture separating equipment. The head is divided into inlet and outlet chambers by a vertical

partition plate extending from the head to the tubesheet. On the secondary side, feedwater

flows directly into the annulus formed by the outer shell and tube bundle wrapper before

entering the bioiler section of the steam generator. ''A 'set of centrifugal moisture separators,

located above the tube bundle,'rembve rost of the&entrained moisture in the steam. Steam

dryers further increase the steam quality.' -

In Table 2.2-la of the LRA, the applicant'idehtified the'following criteria it used to determine the

SSCs that are within the scope of license renewal for the steam generator:

* safety-related (10 CFR 54.4(a)(1)) -

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

In Table 2.3.1.4 of the LRA, the applicant listed the steam generator component types that are

within the scope of license renewal and subject to an AMR, including channel divider plate;

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channel head and integral primary nozzles; closure bolting (primary); closure bolting

(secondary); feedwater distribution assembly (thermal sleeve, piping, and fittings, spargers,

support structure); feedwater inlet nozzle; primary inlet and outlet nozzle safe ends; primary

manway covers and disc inserts; primary moisture separator and sludge collector assembly;

primary nozzle dam rings; secondary moisture separator assembly; secondary-side manways,

handholes, inspection, ports, and covers; stayrod assemblies; secondary shell penetrations;

steam outlet flow limiter; tube bundle wrapper and support assembly; tube support plates, flow

distribution baffles, and anti-vibration bars; tubesheet; U-tubes; upper head (with integral steam

nozzle); and upper shells, lower shells, and transition cones.

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4 and FNP FSAR Section 5.5.2. The staff conducted its

review using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff reviewed the FSAR for any functions delineated under

10 CFR 54.4(a) that the applicant did not identify as intended functions in the LRA; the staff

then evaluated whether the SSCs with such functions will be adequately managed so that the

component intended functions will be maintained consistent with the CLB for the period of

extended operation. The staff did not identify any omissions. The staff next reviewed the LRA

to verify that the applicant had identified all passive or long-lived components that are subject to

an AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant omitted any SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent assessment to

determine whether the applicant did not identify any components that should be subject to an

AMR. The staff found no omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the steam generator components that are within the scope

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the steam generator components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.1.4.3 Conclusion

During its review of 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 steam

generator components. The staff concludes that the applicant has adequately identified the

steam generator components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the steam generator

components 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 FNP UFSAR identified the SCs of the ESFs that are subject to

an AMR for license renewal. The FNP UFSAR defined the ESF systems as the high-head

safety injection system, low-head safety injection system, containment spray system,

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containment cooling system, and PRF system.

For the purpose of license renewal,' the applicant described the containmrent cooling system in

Section 2.3.3.11 of the LRA and the PRF system in Section 2.3.3.10 of the LRA. The applicant

stated that, together', the high-h6ad safety' injection po'rtion of the CVCS and the regenerative

heat removal/loW-head safety injection syste mcomprise the ECCS discussed in NUREG1 801.

For the purpose of license renewal, the applicant included the containment isolation'systern in

the ESFs.

The following sections describe the ESF systems:

* containment spray system

* containment isolation system

* 'emergency core cooling system

2.3.2.1 Containmeht Spray System

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 system., The

applicant stated that the function of the 6o6ntiin' eiit spray system is to spray water into the

containment atmosphere, in the event of a loss-o6f-coolant accident (LOCA) or main steamline

break, to ensure that containment peak pressure r6rain§ below its design value. The

containment spray system operafes in two phases following actuation.: During the initial

(injection) phase of operation, water from ther1efuelihg water storage tank (RWST) is used for

containment spray. During the later (recirculation) phase of operation, water for the

containment spray is recirculated from the containment emergency sump. Baskets located on

the containment floor are' loaded with trisodium )i-osphate, which dissolves into the recirculation

fluid for postaccident sump pH control. The containment spray system is designed to operate

over an extended period of time and under the environmental conditions existing following an

RCS failure.

The staff reviewed the scoping and screening of the sump suction screens and the trisodium

phosphate baskets in Section 2.4.1.4, uContainrnient Internal Structures," of this SER. The

mechanical piping system includes the vortex breakers in the emergency sump.

In Table 2.2-1b of the LRA, the applicant identified the following criteria it used to determine the

SSCs that are within the scope'of licehse renewal f6r the containment spray system:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* 'environm ental qualification (10 CFR 54.4(a)(3))

In Table 2.3.2.1 of the LRA, the applicant listed the containment spray component types that

are within the scope of license renewal and subject to an AMR, including closure bolting,

eductor, encapsulation vessel, flow orifice/element, piping, pump casings, spray nozzles, valve

bodies, and vortex breakers.

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2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1 and FNP FSAR Section 6.2.2 and Appendix 6C to

determine whether the applicant identified the containment spray 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 Section 2.3 of

NUREG-1 800.

In its evaluation, the staff reviewed the FSAR to determine if there were any safety-related

system functions that the applicant had not identified in the LRA as an intended function of the

containment spray system, in accordance with the requirements of 10 CFR 54.4. The staff did

not identify any omissions.

The staff also selected system functions described in the FSAR, and required by 10 CFR 54.4,

to verify that the applicant had not omitted components having intended functions from the

scope of the Rule. The staff also focused on those components that the applicant had not

identified as being subject to an AMR to determine if any components were improperly omitted.

To verify that the applicant identified the components of the containment spray system 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 P&l drawings to the system drawings

and system descriptions in the FSAR to ensure that the referenced P&l drawings were

representative of the containment spray system. The staff then reviewed the referenced P&I

drawings to verify that the applicant had included those portions of the containment spray

system that meet the scoping requirements of 10 CFR 54.4 within the scope of license renewal,

and had identified them as such in LRA Section 2.3.2.1. In addition, the staff determined that

the applicant had identified all containment spray 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's review of LRA Section 2.3.2.1 did not identify areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, the staff did not issue any RAls to determine whether the applicant had properly

applied the scoping criteria of 10 CFR 54.4 and the screening criteria of 10 CFR 54.21.

2.3.2.1.3 Conclusion

During its review of 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 the

containment spray system components. The staff concludes that the applicant has adequately

identified the containment spray 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

containment spray system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.3.2.2 Containment Isolation System

2.3.2.2.1 Summary of Technical Information in the Application

In Section 2.3.2.2 of the LRA, the applicant described the containment isolation system. The

containment isolation system is an ESF that allows appropriate process fluids to pass through

the containment boundary during normal and accident conditions,- while providing for isolation of

containment barrier penetrations, as required, to preserve the integrity of the containment

barrier during accident conditions. Containment barrier penetrations are isolated as required to

prevent uncontrolled or unmonitored leakage of radioactive materials to the environment. The

containment isolation system is not a completely independent system. Rather, the system

comprises specific features included in other systems that penetrate the containment boundary.

The containment pressure monitoring intended function is also included in the containment

isolation system boundary. The monitors provide essential indication of normal and:

postaccident containment pressure conditions and initiate safeguard actuation signals in

response to abnormal containment pressure conditions. Process systems that have license

renewal system intended functions, in addition to containment isolation or containment pressure

monitoring, are addressed in the system screening results in the applicable portion of Section

2.37, "Auxiliary Systems," of the LRA. The process systems or subsystems with license. -

renewal intended functions limited to containment isolation or containment pressure monitoring

include the following:

* containment isolation system

* narrow range containment pressure monitoring (subsystem of the containment spray

system)

* extended range containment pressure monitoring system

* containment leak rate test system

The civil/structural screening described in Section 2.4, uContainments, Structures, and

Component Supports," of this SER includes the pressure boundary (metallic) portions of

electrical penetratiorin, pipe sleeve assembly surrounding process penetrations, and

miscellaneous/spare mechanical penetrations that are not associated with a process system.

The electricaVl&C screening described in Section 2.5, "Electrical and Instrumentation and

Control Systems," of this SER includes the nonmetallic and conductor portions of electrical

penetrations.

In Table 2.2-1 b of the LRA, the applicant identified the following criteria it used to determine the

SSCs that are within the scope of license renewal for the containment isolation system:

* - safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.2.2 of the LRA, the applicant listed the containment isolation system component

types that are within the scope of license renewal and subject to an AMR, including capillary

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tubing (sealed), closure bolting, piping, and valve bodies.

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 and FNP FSAR Section 6.2.4 to determine whether the

applicant identified the containment isolation 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 Section 2.3 of NUREG-1800.

In its evaluation, the staff reviewed the FSAR to determine if there were any safety-related

system functions that the applicant had not identified in the LRA as an intended function of the

containment isolation system, in accordance with the requirements of 10 CFR 54.4. The staff

did not identify any omissions.

The staff also selected system functions described in the FSAR and required by 10 CFR 54.4 to

verify that the applicant did not omit components having intended functions from the scope of

the Rule. The staff also focused on those components that the applicant had not identified as

being subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the containment isolation system 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 P&l drawings to the system

drawings and system descriptions in the FSAR to ensure that the referenced P&l drawings

were representative of the containment isolation system. The staff then reviewed the

referenced P&l drawings to verify that the applicant had included those portions of the

containment isolation system that meet the scoping requirements of 10 CFR 54.4 within the

scope of license renewal and had identified them as such in LRA Section 2.3.2.2. In addition,

the staff determined that the applicant had identified all containment isolation 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's review of LRA Section 2.3.2.2 did not identify areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, the staff did not issue any RAls to determine whether the applicant had properly

applied the scoping criteria of 10 CFR 54.4 and the screening criteria of 10 CFR 54.21.

2.3.2.2.3 Conclusion

During its review of 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 the

containment isolation system components. The staff concludes that the applicant has

adequately identified the containment spray isolation 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 containment spray system components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.3.2.3 Emergency Core Cooling System

The ECCS includes the following systems:

* 'i residual heat rem6vaVlow-head safety injection system

* high-head safety injection portion of the'CVCS system

-refueling water storage tank and transfer system residual

2.3.2.3.1 Summary of Technical Information in the Application

In Section 2.3.2.3 of the LRA, the applicant identified the components of the ECCS.

Residual Heat Removal/Low-Head Safety Iniection

The primary function of the residual heat removal (RHR) system is to remove radioactive decay

heat energy from the reactor core, as well as sensible and pump heat from the RCS, during

plant cooldown and refueling operations. A secondary function of the RHR system is to transfer

refueling'water between the RWST and the refueling canal at the beginning and end of

ref ueling 'operations. 'This system also provides overpressurization protection for the RCS

during low temperature RCS operations.

The RHR system also serves'as the low head portion of the safety injection system. The safety

injection system operates in two phases following a LOCA, injection and recirculation. During

the injection phase, the RHR system delivers borated water to the RCS from the RWST.

During the recirculation phase, the RHR system cools and returns water collected in the

containment emergency sump to the RCS and the containment spray and safety injection

systems to maintain reactor core and containment cooling functions. The sump suction

screens are included in the civil LRA system containment internal structures. The vortex

breakers in the containment emergency sumps are included as part of the mechanical piping

system.

High-Head Safety Iniection 7

The primary purpose of the high-head safety injection system is to deliver borated cooling water

to the reactor core in th-e event of 'a LOCA. The high-head safety injection system is made up

of dedicated components,-such as the accumulators, along with portions of the CVCS. This

combination of components is utilized as the high-head portion of the safety injection system.

The accumulator tanks are charged using high-pressure nitrogen'to provide a passive means of

injection. The nitrogen supply line to the accumulators isolates automatically upon high

penetration 'room pressure to maintain the negative pressure required for the PRF function (see

Section 2.3.3.10 of this SER, uAuxiliary and Radwaste Area Ventilation System"). The highhead safety injection system operates in two phases following a LOCA,- injection and

recirculati6n.' Duringtthe injection phase, the charging pumps deliver borated water to the RCS

from the RWST. 'The'passive accumulators inject borated water into the RCS when the RCS

pressurd'drops below the accumulator pressure. During the recirculation phase, the charging

pumps recirculate water to the'RCS after the water has been cooled by the RHR heat

exchangers.'

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Refueling Water Storage Tank and Transfer System

The RWST serves as a source of emergency borated cooling water for the high-head safety

injection, low-head safety injection, and containment spray during the injection mode. The

RWST is designed to hold enough dilute boric acid solution to fill the refueling canal before

refueling operations, and to provide injection water to support the safety injection system. The

RWST can also be used to fill the refueling cavity by means of the refueling water purification

pump.

In Table 2.2-1 b of the LRA, the applicant identified the following criteria it used to determine the

SSCs that are within the scope of license renewal for the ECCS:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.2.3 of the LRA, the applicant listed the ECCS component types that are within the

scope of license renewal and subject to an AMR, including charging/safety injection pump

miniflow orifices, closure bolting, encapsulation vessel, flow orifice/element, RHR heat

exchanger (channel head), RHR heat exchanger (shell), RHR heat exchanger (tubesheet),

RHR heat exchanger (tubes), oil cooler (shell), oil cooler (channel head), oil cooler (tubes),

piping, high head and RHR pump casings, safety injection accumulators, RWSTs, valve bodies,

and vortex breaker.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 and FNP FSAR Sections 5.2.2.4, 5.5.7, and 6.3. The

staff conducted its review using the evaluation methodology described in Section 2.3 of this

SER, in accordance with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff reviewed the FSAR for any functions delineated under

10 CFR 54.4(a) that the applicant had not identified as intended functions in the LRA; the staff

then evaluated whether that the SSCs with such functions will be adequately managed so that

the component intended functions will be maintained consistent with the CLB for the period of

extended operation. The staff did not identify any omissions. The staff next reviewed the LRA

to verify that the applicant had identified all passive and long-lived components subject to an

AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant omitted any SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent assessment to

determine whether the applicant omitted any components that should be subject to an AMR.

The staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the ECCS 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

ECCS components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.2.3.3 Conclusion

During its review of 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 the

ECCS components. The staff concludes'that the'applicant has adequately identified the ECCS

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 ECCS components that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

2.3.3 Auxiliary Systems

In Section 2.3.3 of the LRA, the applicant identified the components of the auxiliary systems

that are subject to an AMR for license renewal. Sections 2.3.3 and 2.4.2.1 of the LRA describe

the following auxiliary systems and structures:

* new fuel storage

* spent fuel storage

* spent fuel pool cooling and cleanup

* overhead heavy and refueling load handling

* open-cycle cooling water

* closed-cycle cooling water

* compressed air

* chemical and volume control

* 'control room area ventilation

* auxiliary and radwaste area ventilation

* primary containment ventilation '

* yard structures ventilation

* fire protection

* diesel fuel oil

* emergency diesel generator

* demineralized water

* high-energy line break detection

* hydrogen control

* liquid waste and drains

* oil-static cable pressurization

* potable and sanitary water

* radiation monitoring

* reactor makeup water storage

* sampling

2.3.3.1 New Fuel Storage

2.3.3.1.1 Summary of Technical Information in the Application

In Seciion 2.4.2.1, "Auxiliary Building" of the LRA, the applicant described new fuel storage.

The fuel st6rage facility consists of the new'fuel storage area, SFP (including the structure,

liner, and fuel storage racks), fuel transfercanal,;cask storage area,-cask wash area, and

rooms containing supporting equipment. Thee inew fuel storage area is adjacent to the SFP, but

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is a separate area designed for dry storage of new fuel assemblies prior to their transfer into

the SFP.

In Table 2.2-1c of the LRA, the applicant identified the following criterion it used to determine

the SSCs that are within the scope of license renewal for new fuel storage:

* safety-related (10 CFR 54.4(a)(1))

In Table 2.4.2.1 of the LRA, the applicant listed the auxiliary building component types, which

include the new fuel storage component types, that are within the scope of license renewal and

subject to an AMR, including compressible joints and seals, concrete (exterior above grade),

concrete (exterior below grade), concrete (foundation), concrete (interior), concrete (roof slab),

nonfire doors, fire doors, fire seals, masonry walls (all), new fuel storage racks (storage rack

assembly), penetration sleeves, spent fuel storage racks (storage racks), steel components (all

structural steel), and steel components (liners).

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1 and FNP FSAR Section 9.1. The staff conducted its

review using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff reviewed the FSAR for any functions delineated under

10 CFR 54.4(a) that the applicant did not identify as intended functions in the LRA; the staff

then evaluated that the SSCs with such functions will be adequately managed so that the

intended component functions will be maintained consistent with the CLB for the period of

extended operation. The staff did not identify any omissions. The staff next reviewed the LRA

to verify that the applicant had identified all passive or long-lived components subject to an

AMR, in accordance with 10 CFR 54.21(a)(1).

2.3.3.1.3 Conclusion

During its review of 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 new

fuel storage components. The staff concludes that the applicant has adequately identified the

new fuel storage 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 new fuel storage

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.2 Spent Fuel Storage

2.3.3.2.1 Summary of Technical Information in the Application

In Section 2.4.2.1 of the LRA, the applicant described spent fuel storage. The fuel storage

facility consists of the new fuel storage area, SFP (including the structure, liner, and fuel

storage racks), fuel transfer canal, cask storage area, cask wash area, and rooms containing

supporting equipment. The SFP is designed for underwater storage of spent fuel assemblies

after their removal from the reactor. The spent fuel pool bridge crane transports the fuel

assemblies. The fuel transfer canal is an intermediate handling area and is connected to the

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refueling canal inside containment by the fuel transfer tube. The futel transfer canal is

separated from the SFP by a removable gate. The fuel transfer cahal may be drained to

service the fuel-handling equipment or flooded for fuel handling.

In Table 2.2-1 c of the LRA,- the applicant identified the following criterion it used to determine

the SSCs that are within the scope of license renewal for spent fuel storage:

safety-related (10 CFR 54.4(a)(1)) '

In Table 2.4.2.1 of the LRA, the applicant listed the auxiliary building component types, which

include the spent fuel storage component types, that are within the scope of license renewal

and subject to an AMR, including compressible joints and seals, concrete (exterior above

grade), concrete (exterior below grade), coridr6te6(foundation), concrete (interior), concrete

(roof slab), nonfire doors, fire doors, fire seals, masonry walls (all), new fuel storage racks

(storage rack assembly), penetration sleeves; spent fuel storage racks (storage racks), steel

components (all structural steel), and steel components (liners).

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.1 and FNP FSAR Section 9.1. The staff conducted its

review using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function of the spent fuel storage system in the LRA, in accordance with the

requirements of 1 0 CFR 54.4(a). The staff did not identify any omissions. The staff then

evaluated, in accordance with the screening process described in Section 2.3 of this SER, that

the applicant had identified all passive and long-hued components subject to an AMR, in

accordance with 1 0 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.2.1 identified areas in which it needed additional

information to complete the evaluation-of th6applicant's scoping and screening results.

Therefore, by letter dated December 12, 2003, the staff issued several RAls to determine

whether the applicant had properly applied the scoping criteria of 10 CFR 54.4(a) and the

screening criteria of '1 0 CFR 54.21 (a)(1). The following describes'the staff's RAIs and the

applicant's responses, dated January 9, 2004.:

RAI 2.3.3.2-1

Section 9.1.2.1 of the FNP FSAR describes a tradnsport container'with a pellet canister trap and

a fuel rod storage canister as additional storage containers for spent fuel rods and fuel rod

debris. These storage containers provide the intended functions of radiation shielding and

debris protection. The staff requested that the'applicant justify the exclusion of these

components from the scope of license renewal and from an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 1 0 CFR 54.21 (a)(1), respectively.

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Applicant's Response and Staff's Evaluation

By letter dated January 9, 2004, the applicant responded that the component intended function

for the pellet canister trap, transport container, and the fuel rod storage canister is to provide

structural support to facilitate storage and transport. The applicant concurred that the transport

containers with a pellet canister trap, as well as the fuel rod storage containers for spent fuel

rods and fuel rod debris in the spent fuel storage racks, are within the scope of license renewal

and subject to an AMR. Therefore, the applicant stated that these components will be added to

the scope of license renewal associated with the spent fuel storage facility as part of the

auxiliary building scoping results in LRA Section 2.4.2.1.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-1 acceptable

because the applicant concurs that the transport containers and the fuel rod storage containers

are within the scope of license renewal and subject to an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively. Therefore, the staff

considers RAI 2.3.3.2-1 resolved.

RAI 2.3.3.2-2

License renewal boundary drawings D-175043L (Unit 1) and D-205043L (Unit 2) show strainers

on the spent fuel pool cooling system suction and supply lines that are excluded from the scope

of license renewal. Degraded or blocked strainers could impair the performance of the decay

heat removal intended function. The staff requested that the applicant justify the exclusion of

these components from the scope of license renewal and from an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively.

Applicant's Response and Staff's Evaluation

By letter dated January 9, 2004, the applicant responded that it had excluded the strainers from

the scope of license renewal because they do not perform a license renewal intended function,

as defined by 10 CFR 54.4(a).

The applicant provided the following justification for the exclusion of the strainers from the

scope of license renewal:

The strainers are provided as a prudent design provision but do not perform a safety-related

function or support a regulated event. Pool cleanliness and foreign material exclusion control are

maintained, so there is no source of debris. Blockage of strainers is an event-driven scenario

beyond the licensing basis for the system.

There is no applicable failure mechanism that can affect a safety-related function. There is no

aging effect for stainless steel in a borated water environment that would result in a failure that

could impact the spent fuel pool cooling safety function. In addition, the FNP water chemistry

program is already credited in the LRA for managing the spent fuel pool's water chemistry.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-2 acceptable

because it adequately justifies that the strainers on the spent fuel pool cooling system suction

and supply lines do not perform an intended function, in accordance with the requirements of

10 CFR 54.4(a), and clarifies their exclusion from an AMR, in accordance with the requirements

of 10 CFR 54.21(a)(1). Therefore, the staff considers RAI 2.3.3.2-2 resolved.

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2.3.3.2.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant omitted any SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent 'assessment to

determine whether the applicant had omitted any components that should be subject toan

AMR. The staff did not identify any omissions. 'On the basis of its review, the staff concludes

that the applicant has adequately idertified the components of the spent fuel storage system

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant has adequately identified the components of the spent fuel storage system that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.3 Spent Fuel Pool Cooling and Cleanup System

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 spent fuel pool cooling and cleanup

system. The spent'fuel cooling 'and cleanup 'system removes decay heat generated by spent

fuel assemblies stored in the SFP. The'system can also be used to maintain clarity and purity

of the water in the SFP, the fuel transfer canal,-and the RWST.

The spent fuel pool cooling and cleanup system consists of two cooling trains,-a purification

loop, and a surface skimmer loop. The SFP cooling portion of the system removes decay heat

from the spent fuel stored in the SFP to maintain established temperature limits within the pool

and to minimize evaporative losses. Heat is transferred from the spent fuel pool cooling-and

cleanup system through the heat exchanger to the 6omponent cooling system.

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the spent fuel pool cooling and cleanup system components which are within the

scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety related function (10 CFR 54.4(a)(2))

In Table 2.3.3.3 of the LRA, the applicant listed the spent fuel pool cooling and cleanup system

component types that are within the scope of license renewal and subject to an AMR, including

closure bolting, heat exchanger (channel head), heat exchanger (shell), heat exchanger (tubesheet), heat exchanger (tubes), piping, pump'casings, and valve bodies.

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3 and FNP FSAR Section 9.1.3. The staff conducted its

review using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation; the staff used the scoping'process described in Section 2.3 of this SER to

review'the FSAR to determine if the applicant had omitted any system functions as an intended

function'of the spent fuel pool cooling and cleanup system in the LRA, in accordance with the

requirements of 10 CFR 54.4(a). The staff 'did not identify any omissions. The staff then

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evaluated, in accordance with the screening process described in Section 2.3 of this SER, that

the applicant had identified all passive and long-lived components subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.3 identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff issued an RAI to determine whether the

applicant had 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 RAI and the applicant's response,

dated April 7, 2004.

RAI 2.0-2A (D-RAI 2.3.3.3-1)

License renewal boundary drawings D-1 75043L (Unit 1) and D-205043L (Unit 2) do not appear

to show any source of makeup water to the spent fuel pit (spent fuel pool) within the scope of

license renewal. Section 9.1.3.3.2 of the FNP FSAR states that the FNP SFP was designed in

accordance with RG 1.13, "Spent Fuel Storage Design Basis," Revision 1, which requires a

diversity of makeup water sources to the SFP. Section 9.1.3.3.2 of the FNP FSAR also credits

the demineralized water system and the reactor makeup water storage (RMWS) system as

being available to supply makeup water to the SFP. Section 2.3.3.23 of the LRA states, "The

license renewal intended function of the Reactor Makeup Water Storage System is to provide

an assured seismic Category I make-up source to ... the spent fuel pool."

The staff requested that the applicant justify the exclusion of the piping and components

connecting the demineralized water system and the RMWS system to the spent fuel pool from

the scope of license renewal and from an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively.

Applicant's Response and Staff's Evaluation

By letter dated April 7, 2004, the applicant responded that the reactor makeup water hose

station in the spent fuel pool area provides an assured seismic Category 1 source of makeup

water to the pool. This hose station and the supply is within the scope of license renewal, as

described in LRA Section 2.3.3.23 and as shown on the RMWS system license renewal

boundary drawings D-175036L and D-205036L.

The applicant also clarified that demineralized water provides for normal makeup to the spent

fuel pool for evaporative losses and is not required for any safety-related or regulated event.

Therefore, this section of piping does not perform any intended function subject to the criteria of

10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3). The applicant further stated that portions of the

demineralized water supply are within the scope of license renewal, in accordance with the

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

Based on its review, the staff finds the applicant's response to RAI 2.0-2A acceptable because

it adequately justifies the basis for including the reactor makeup water hose station in the spent

fuel pool area within the scope of license renewal. The applicant also justified the exclusion of

certain piping sections connecting the demineralized water system to the spent fuel pool from

the scope of license renewal, in accordance with the requirements of 10 CFR 54.4(a)(1) and

10 CFR 54.4(a)(3). Therefore, the staff considers RAI 2.0-2A resolved.

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2.3.3.3.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant had identified all SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent assessment'to"

determine whether the applicant identified all components that should be subject to an AMR.

The staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the cornponents'of the spent fuel pool cooling and cleanup

system that are within the scope o license renewal,' as 'required by 10 CFR 54.4(a), and that

the applicant has adequately identified the components of the spent fuel pool cooling and

cleanup system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.4 Overhead Heavy and Refueling Load Handling System

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 overhead heavy and refu eling load

handing system. The overhead heavy'and refueling load handling system includes the

refueling' and servicing'equipment and special tools, as well as the auxiliary building and

containment cranes, hoists, and elevators.

The overhead heavy and refueling load handling system includes the fuel-handling 'equipment

required to 'refuel the reactor. This system'prbvides for the handling and storage of fuel

assemblies from receipt of the new fuel to thieshipmrent of spent fuel. The major fuel-handling

equipment includes'the'containment polar crane, reactor cavity manipulator cranes,' spent fuel

bridge cranes, 'and spent fuel cask crarie. This co'mponent category also' includes the special

tools and adapters used for lifting and handling the vessel head, internals, fuel assembly -

inserts, etc. Fuel-handling devices have provisions to avoid dropping or jamming of fuel

assemblies during transfer operation.

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine which components of the overhead heavy and refueling load handling system are

within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* 'non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

In Table 2.3.3.4 of the LRA, the applicant fisted the overhead heavy and refueling load handling

system component types that are within the scope of license renewal and subject to an AMR,

including baseplates and anchors for attachment to structures and retaining clips, cranes

including bridge and trolley (structural girder's), arid rail system (rail).

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 and FNP FSAR Section 9.1.4.' Thee staff conducted its

review using the evaluation methodology des6ribed in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its'evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

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I

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function of the overhead heavy and refueling load handling system in the LRA, in

accordance with the requirements of 10 CFR 54.4(a). The staff did not identify any omissions.

The staff then evaluated, in accordance with the screening process described in Section 2.3 of

this SER, that the applicant had identified all passive and long-lived components subject to an

AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.4 identified areas in which it needed additional

information to complete the review of the applicant's scoping and screening results. Therefore,

by letter dated March 23, 2004, the staff issued several RAIs to determine whether the

applicant had 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,

dated April 7, 2004.

RAI 2.3.3.4-1

In LRA Section 2.3.3.4, the applicant provided a brief description of the overhead heavy and

refueling load handling system. This section of the LRA identifies the containment polar crane,

the reactor cavity manipulator crane, the spent fuel pool bridge crane, the spent fuel cask

crane, and the special tools and adapters used for lifting and handling refueling loads as being

part of the overhead heavy and refueling load handling system. However, the LRA does not

identify which of these cranes have components subject to an AMR, nor does LRA Table

2.3.3.4 identify any of the special tools and adapters used for lifting and handling refueling

loads as being subject to an AMR. The staff requested that the applicant identify the specific

cranes that contain components subject to an AMR, in accordance with the requirements of

10 CFR 54.21 (a)(1), and justify the exclusion of the special tools and adapters used for lifting

and handling refueling loads from an AMR.

Applicant's Response and Staff's Evaluation

By letter dated April 7, 2004, the applicant responded that the containment polar crane, the

reactor cavity manipulator crane, the spent fuel pool bridge crane, and the spent fuel cask

crane are within the scope of license renewal and contain components subject to an AMR, in

accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively.

The applicant further stated that the special tools and adapters used for lifting and handling the

reactor vessel head, internals, and fuel assembly inserts are active components within the

scope of license renewal and are not subject to an AMR, in accordance with the requirements

of 10 CFR 54.21(a)(1).

In response to the staff's request to identify any of the special tools and adapters within the

scope of license renewal used for lifting and handling of refueling loads, the applicant stated

that these include the head lifting rig, rod control cluster handling tool, thimble plug handling

tool, burnable poison rod assembly tool, and spent fuel-handling tool. The applicant's scoping

process determined that these devices performed their intended functions with moving parts

and/or a change in configuration and therefore are not subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-1 acceptable

because it (1) identifies the cranes or hoists that are within the scope of license renewal and

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subject to an AMR, in accordance with the requirements of 10 CFR'54.4(a) and

10 CFR 54.21 (a)(1), respectively, and (2) justifies that the special t6ols and adapters used for

lifting and handling of refueling loads perform their intended functions with moving parts and/or

a change in configuration and therefore are excluded from an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1). Therefor&, the staff considers RAI 2.3.3.4-1 resolved.

RAI 2.3.3.4-2

Several structures typically contain cranes'or hoists located above or near safety-related

equipment (e.g., the intake structure and the diesel generator building). The staff requested

that the applicant describe how it evaluated areas containing cranes or hoists near safetyrelated equipment to identify those cranes or hoists subject to an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1), and explain where the LRA'identifies those components in

the LRA.

Apolicant's Resmonse and Staff's Evaluation

By letter dated April 7, 2004, the applicant responded that cranes and hoists were evaluated by

the civil discipline'for the LRA, described in'LRA Section 2.1.3.2. In the LRA, a spaces

approach" was used to place all civifstructural components in a structure housing safety-related

SSCs within the scope of license renewal. Therefore, the applicant considered all cranes and

hoists located above or near safety-related equipment within scope.

The applicant further stated that cranes associated with overhead heavy and fuel-related load

handling were grouped together in LRA Section 2.3.3.4 (to align with the NUREG-1 801

grouping) with the component types subject to an AMR. Table 2.3.3.4 of the LRA also identifies

these groups. The applicant included all other cranes and hoists in scope as part of the overall

evaluation of its structure in LRA Section 2.4. The components subject to an AMR are included

in the component type "steel cromponents-all structural steel" for the associated structure, as

listed in the table for components 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 how the applicant evaluated areas containing cranes and hoists

near safety-related equipment. In addition, the response identifies the cranes or hoists subject

to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1). Therefore, the staff

considers RAI 2.3.3.4-2 resolved.

2.3.3.4.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant had omitted 'any SSCs'thdt should be within the 'scope of license renewal.

The staff did not identify any omissions. In addition, the staff performed an independent

assessment to' d6termine if the applicant had identified all components that should be subject to

an AMR. The staff found no omissions. On'the basis of its review, the staff concludes that the

applicant has adequately identified the c mponents of the overhead heavy and refueling load

handing &ystem-that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and that the applicant has adequately identified the components of the overhead heavy and

refueling load handing system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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.1-

2.3.3.5 Open-Cycle Cooling Water System

2.3.3.5.1 Summary of Technical Information in the Application

In Section 2.3.3.5 of the LRA, the applicant described the open-cycle cooling water system.

The open-cycle cooling water system includes the service water system and portions of the

river water system (service water pond water-level instruments). The service water system

provides cooling water to plant loads during normal and emergency modes of operation. Heat

loads include the component cooling water system, room coolers, containment coolers, EDGs,

and certain turbine building loads. The system also provides a backup supply to the AFW

system.

The service water system draws cooling water from the service water pond, which serves as the

ultimate heat sink for FNP. The river water system supplies makeup water to the service water

pond. The only portions of the river water system that are in the scope of the open-cycle

cooling water system are the service water pond water-level instruments used for aligning the

service water system into its emergency recirculation mode.

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine which components of the open-cycle cooling water system are within the scope of

license renewal:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

* anticipated transient without scram (10 CFR 54.4(a)(3))

In Table 2.3.3.5 of the LRA, the applicant listed the open-cycle cooling water system

component types as within the scope of license renewal and subject to an AMR, including air

compressor lube oil cooler (channel head); air compressor lube oil cooler(shell); air compressor

lube oil cooler(tubes/tubesheet); air compressor intercooler, aftercooler, and bleed-off air cooler

(shells); air compressor bleed-off air cooler (channel head); air compressor intercooler,

aftercooler, and bleed-off air-cooler (tubes/tubesheet); closure bolting; component cooling water

(CCW) heat exchanger (channel head); CCW heat exchanger (shell); CCW heat exchanger

(tubesheet); CCW heat exchanger (tubes); containment and ESF room coolers (channel head

and tubes); flow orifice/element; piping; piping with guard pipe; service water pump casings;

lube and cooling water pump casings; strainers (element); strainers (shell); and valve bodies.

In its response to RAI 2.1-1 (discussed in Section 2.1.3.1 of this SER), the applicant changed

the methodology it used for scoping of non-attached, non-safety-related piping for the opencycle cooling water system, in accordance with 10 CFR 54.4(a)(2). By letter dated June 4,

2004, the applicant submitted the supplemental information associated with the determination

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

10 CFR 54.4(a)(2), as a result of the revised scoping methodology (see Enclosure 2, "Joseph

M. Farley Nuclear Plant Units 1 and 2, Application for License Renewal, Supplemental

Information Related to 10 CFR 54.4 (a)(2)").

The applicant's change in methodology expanded the mechanical SSCs within the scope of

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license renewal. -In its suppl6mental information related to 10 CFR 54.4(a)(2), the applicant

listed the impact of changes' inthe 10 CFR 54.4(a)(2) scoping meitodology on the LRA results

for the in-scope components of the open-cycle cooling water system.' Although this table shows

an increase in the number of in-scope SSCs for the open-cycle cooling water system, the

applicant stated that the component types do not differ from those listed in LRA Table 2.3.3.5.

2.3.3.5.2 Staff Evaluation

The staffreviewed LRA Section 2.3.3.5 and FNP FSAR Sections 9.2.1 and 9.5.5. The staff

conducted its review usinrg the evaluation methodology described in Section 2.3 'of this SER, in

accordance with the guidance described in Section 2.3 of NUREG-1800.

In its evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function of the open-cycle cooling water system from the LRA, in accordance with the

requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff then

evaluated, in accordance with the screening' process described in Section 2.3 of this SER, that

the applicant had identified all passive`and lon-g-lived components subject to an AMR, in

accordance with 10 CFR 54.21 (a?(1).' '

The staff's review of LRA Section 2.3.3.5 identified areas in which it needed additional

inf6rmation to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the stiff issued several RAls to determine whether

the applicant had 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, dated April 22, 2004, and June 18, 2004.

RAI 2.3.3.5-1

(a) On license renewal boundary drawing A-200475L, the compressed air filter N2P16F560

is shown within the scope of license renewal. However, LRA Table 2.3.3.5 does not list

the compressed air filter as a component type subject to an AMR. Air filters serve the

intended function of pressure boundary and are passive and long-lived components.

Therefore, the staff requested that the applicant justify the exclusion of the filter housing

from an AMR, in accordance with the're4uiremrents of 10 CFR 54.21(a)(1).

(b) On license renewal boundary drawings A-i 70059L and'A-200475L, two components,

which appear to be a roto-f low meter and a pressure regulator, have symbols that are

not identified in the license renewal boundary drawings for P&ID legend and symbols.

These components are shown within the scope of license renewal. The staff requested

'that the applicant provide' additional iriforrriation to identify these components and clarify

whether they are inr6luded in LRA TabI6 2.3.3.5 as being subject to an AMR. If not,' the

staff requested that the applicant justify their exclusion from an AMR, in accordance with

the requirements of 10 CFR 54.21 (a)(1).

Applicant's Resionse and Staff's Evaluation

(a) By letter dated April 22, 2004, the applicant responded that the air filter is'typically

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I

supplied by the valve vendor and is mounted on the valve as part of the valve operator

assembly. The air filter is an integral part of the valve operator and included as part of

the valve operator component for license renewal. The valve operator only performs an

active function and therefore is not subject to an AMR. The applicant manages agerelated degradation of the valve operator under the requirements of the Maintenance

Rule.

During a telephone conference between the applicant and the staff on May 24, 2004,

the staff agreed to consolidate RAI 2.3.3.5-1a, RAI 2.3.3.5-1b, RAI 2.3.4.1-1, and

portions of RAI 2.2-5b for the pneumatic valve operator air tanks into a revised

RAI 2.2-5b because the applicant's responses to these RAIs were related to the integral

parts of valve operators. Therefore, by letter dated June 25, 2004, the staff issued the

revised RAI 2.2-5b. Section 2.2.3 of this SER provides the revised RAI 2.2-5b and the

applicant's response.

(b) By letter dated April 22, 2004, the applicant responded that these components are a

check valve and a self-contained pressure regulator valve which are part of the active

valve operator assembly. The check valve and self-contained pressure regulator valve

shown is typically supplied by the valve vendor and mounted on the valve as part of the

valve operator assembly. The check valve and self-contained pressure regulator valve

are integral parts of the valve operator and included as part of the valve operator

component for license renewal. The valve operator only performs an active function and

therefore is not subject to an AMR. The applicant manages age-related degradation of

the valve operator under the requirements of the Maintenance Rule.

During a telephone conference between the applicant and the staff on May 24, 2004,

the staff agreed to consolidate RAI 2.3.3.5-1a, RAI 2.3.3.5-1b, RAI 2.3.4.1-1, and

portions of RAI 2.2-5b for the pneumatic valve operator air tanks into a revised

RAI 2.2-5b because the applicant's responses to these RAls were related to the integral

parts of valve operators. Therefore, by letter dated June 25, 2004, the staff issued the

revised RAI 2.2-5b. Section 2.2.3 of this SER provides the revised RAI 2.2-5b and the

applicant's response.

The staff finds the supplemental information related to 10 CFR 54.4(a)(2) in the June 4, 2004,

Enclosure 2 (discussed in Section 2.2.3) to be acceptable, on the basis that it adequately

identified all open-cycle cooling water system's non-safety-related SSCs that are added to the

scope of license renewal as a result of the changed 10 CFR 54.4(a)(2) scoping methodology.

2.3.3.5.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant had omitted any SSCs that should be within the scope of license renewal.

The staff did not find any omissions. In addition, the staff performed an independent

assessment to determine whether the applicant had identified all components that should be

subject to an AMR. The staff did not identify any omissions. On the basis of its review, the

staff concludes that the applicant has adequately identified the components of the open-cycle

cooling water system that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the components of the opencycle cooling water system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.6 Closed-Cycle Cooling Water System

2.3.3.6.1 Summary of Technical Information in the Application

In Section 2.3.3.6 of the LRA, the applicant described the closed-cycle cooling water system.

The closed-cycle cooling water system includes the component cooling water system. The

component cooling water system is a closed-loop system that transfers heat to the service

water system from components which process radioactive fluid. The component cooling water

system acts as an intermediate heat transfer system between potentially radioactive heat

sources and the-service water system to reduce the probability of radioactive releases to the

environment resulting from a leaking component. The primary safety function of the component

cooling water system is removal of heat from various safety-related components.

In Table 2.2-1 c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the closed-cycle cooling water system components which are within the scope of

license renewal:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

e fire protection (10 CFR 54.4(a)(3)).

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.6 of the LRA, the applicant listed the closed-cycle cooling water system

component types as within the scope of license renewal and subject to an AMR, including

closure bolting, flow orifice/element, reactor coolant drain tank (RCDT) heat exchanger (shell),

RCDT heat exchanger (tubes and tubesheet), piping, pump casings, component cooling water

(CCW) surge tanks, and valve bodies.

In its response to RAI 2.1-1 (discussed in Section 2.1.3.1 of this SER), the applicant changed

the methodology used for scoping of non-attached, non-safety-related piping for the closedcycle cooling water system, in accordance with 10 CFR 54.4(a)(2). By letter dated June 4,

2004, the applicant submitted the supplemental information associated with its determination of

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

10 CFR 54.4(a)(2), as a result of the revised scoping methodology (see Enclosure 2, "Joseph

M. Farley Nuclear Plant Units 1 and 2, Application for License Renewal, Supplemental

Information Related to 10 CFR 54.4 (a)(2)").

The revised methodology expanded the number of mechanical SSCs within the scope of

license renewal. In its supplemental information related to .10 CFR 54.4(a)(2), the applicant

listed the impact of its changes to the 10 CFR 54.4(a)(2) scoping methodology on the LRA

results for the in-scope components of the closed-cycle cooling water system. Although this

table shows an increase in the in-scope SSCs for the closed-cycle cooling water system, the

applicant stated that the component types do not differ from those listed in LRA Table 2.3.3.6.

2.3.3.6.2 -Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and FNP FSAR Section 9.2.2. The staff conducted its

review using the evaluation methodology-described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

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.1

In its evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function of the closed-cycle cooling water system in the LRA, in accordance with the

requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff then

evaluated, in accordance with the screening process described in Section 2.3 of this SER, that

the applicant had identified all passive and long-lived components subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.6 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff issued several RAIs to determine whether

the applicant had 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, dated April 22, 2004.

RAI 2.3.3.6-1

(a) For FNP Units 1 and 2 RCDT heat exchangers, LRA Table 2.3.3.6 lists the heat

exchanger tubesheet within the scope of license renewal and subject to an AMR.

However, the applicant excluded the heat exchanger channel from the scope of license

renewal on license renewal boundary drawings D-175002L and D-205002L. Heat

exchanger channels serve the intended function of pressure boundary and are passive

and long-lived components. The staff requested that the applicant justify the exclusion

of the RCDT heat exchanger channel from the scope of license renewal and from an

AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1),

respectively.

(b) For FNP Units 1 and 2 RCDT heat exchangers, Table 2.1-3 of NUREG-1 800 lists heat

transfer and pressure boundary as the intended functions of the heat exchanger. The

staff requested that the applicant clarify why LRA Table 2.3.3.6 does not list heat

transfer as an intended function for the RCDT heat exchangers.

ApDlicant's Response and Staff's Evaluation

(a) By letter dated April 22, 2004, the applicant responded that the channel side of the

RCDT heat exchanger is in the LW&Ds system and processes reactor coolant liquid

waste from the RCDT. Processing reactor coolant liquid waste from the RCDT is not in

scope for 10 CFR 54.4, however those components that perform the containment

isolation function are within the scope of license renewal. The shell and tubeside of the

RCDT heat exchanger (including tubesheets) is in the component cooling water system

and is in scope to preserve the intended function of pressure boundary for the CCW

components. The applicant further explained that the components of the RCDT heat

exchanger that perform the intended function of pressure boundary are the tubes

(internal and external surfaces), the tubesheets, and the shell. These components are

in scope and highlighted on the license renewal boundary drawings D-175042L and D175002L (Unit 1) and D-205042L and D-205002L (Unit 2). The channel side of the

RCDT heat exchanger does not come in contact with the CCW fluid pressure boundary

and is not relied upon to preserve the intended function of pressure boundary for the

CCW components. A failure in the LW&Ds system pressure boundary (i.e., the channel

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side of RCDT heat exchanger) will not have an adverse effect on the intended function

of pressure boundary for the CCW system. -

The applicant further noted that the shell and tube portions of the RCDT heat exchanger

are in scope only because the shell side (i.e., CCW) is not automatically isolated during

an emergency. The intended function of pressure boundary for the CCW components

must be preserved to assure no loss of CCW inventory during an emergency, when

CCW cooling of other safety-related equipmntit is required. Because processing reactor

coolant liquid waste from the RCDT is not in scope for 10 CFR 54.4, the heat transfer is

not an in-scope intended function for this heat exchanger and should not appear in LRA

Table 2.3.3.6.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-1 a,

acceptable because it adequately explains that the channel side of the RCDT heat

exchanger does not come in contact with the CCW fluid pressure boundary and is not

relied upon to preserve'the intended function of pressure boundary for the CCW

components. Thus, the applicant excluded it from the scope of license renewal, in

accordance with'the requirements of 10 CFR 54.4(a). Therefore, the staff considers

'RAI 2.3.3.6-1a resolved.

(b) By letter dated April 22, 2004, the applicant responded that processing reactor coolant

liquid waste from the RCDT is not in scope for 10 CFR 54.4(a). Therefore, the heat

transfer is not a license renewal intended function for this RCDT heat exchanger and

should not be listed in LRA Table 2.3.3.6.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-1 b

acceptable because it adequately justifies that heat transfer is not an intended function

for the RCDT heat exchanger,'since the processing reactor coolant liquid waste from

the RCDT is not in scope. Thus, LRA Table 2.3.3.6 does not list heat transfer as an

intended function for the RCDT heat exchangers. Therefore, the staff considers RAI

2.3.3.6-1b resolved.

RAI 2.3.3.6-2

The applicant excluded the FNP Units 1 -and 2 postaccident sample coolers depicted on license

renewal boundary drawings D-1 75002L and D-205002L from the scope of license renewal.

However, these coolers are within the scope of license renewal on the Units 1 and 2 sampling

system license renewal boundary drawings D-175009L and D-205009L. Coolers, valve bodies,

and pipes serve the intended function of pressure boundary and are passive and long-lived..

components.

(a) The staff requested that the applicant explain why it excluded the postaccident sample

coolers depicted on license renewal boundary drawings D-175002L and D-205002L,

from the scope of license renewal. -

(b) The staff requested that the applicant explain whether the component cooling water

system pipe segments and valves (e.g., globe valve NV1 81 A) associated with these

coolers should be within the scope of the license renewal and subject to an AMR. If not,

the staff requested that the applicant justify the exclusion of these components from the

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scope of license renewal and from an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively.

Applicant's Response and Staff's Evaluation

(a) By letter- dated April 22, 2004, the applicant responded that the tube side of the

postaccident sample coolers is in the sampling system and in scope for the fire

protection requirements of (10 CFR 50.48) of 10 CFR 54.4(a)(3). In the event of a fire,

manual sampling of-certain parameters is performed to determine that an adequate cold

shutdown margin has been achieved. The tube side of these coolers is in scope for

pressure boundary integrity to maintain a flowpath to the sample sink. These coolers

are not in scope for the intended function of heat exchange because the samples are

taken when the fluid is relatively cool (approximately 200 IF).

The applicant further stated that the shell side of these coolers is in the component

cooling water system and not in scope because the shell side does not come in contact

with the fluid pressure boundary of the tube side of the cooler and the CCW cooling flow

is not required in the event of a fire. The applicant clarified that the intended function of

exchange heat, as shown in LRA Tables 2.3.3.24 and 3.3.2-24 for these coolers, is

incorrect and is removed.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-2a

acceptable because it adequately explains the scoping differences between the tube

side and the shell side of the postaccident sample coolers depicted on the license

renewal boundary drawings. Therefore, the staff considers RAI 2.3.3.6-2a resolved.

(b) By letter dated April 22, 2004, the applicant responded that the CCW pipe segments

and valves associated with the postaccident sample coolers are located on the

nonsafety-related miscellaneous equipment header which automatically isolates on

certain signals, such as low-low level in the surge tank. Therefore, the applicant

excluded them from the scope of license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-2b

acceptable because it justifies the exclusion of the CCW pipe segments and valves

associated with the postaccident sample coolers from the scope of license renewal, in

accordance with the requirements of 10 CFR 54.4(a). Therefore, the staff considers

RAI 2.3.3.6-2b resolved.

RAI 2.0-21 (D-2.3.3.6-3)

License renewal boundary drawings D-1 75002L and D-205002L have notations that are not

explained in the standard P&ID symbol legend or license renewal boundary drawing legend.

For example, barriers shown on license renewal boundary drawings D-175002L and D-205002L

are not defined in the component cooling water system drawings or the legend drawings. The

staff requested that the applicant define these notations and explain the significance of

including these barriers on the license renewal boundary drawings.

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Aoplicant's Response and 'Staff's Evaluat -on i 

By letter dated April 22, 2004, the applicant responded that the barriers addressed in RAI 2.0-21

(D-RAI 2.3.3.6-3) are' in-scope-con'cete'walls' and tare included in the civil/structural portion of

the LRA. -The'applicant further stated that'structural components are not shown on mechanical

boundary drawings, anad in cases in which the'structural components are shown on the

mechanical boundary drawings, they are not highlighted because they are excluded from the

scope of license renewal. -t

Based on its review, the staff finds the applicant's response to RAI 2.0-21 acceptable because it

explains why the applicant did not define the notations on the standard P&ID symbol legend

and the license renewal boundary drawings. The applicant also identified the barriers

addressed in the RAI. Therefore, the staff considers RAI 2.0-21 resolved.

The staff finds the supplemental information related to 10 CFR 54.4(a)(2) in the June 4, 2004,

Enclosure 2 (discussed in Section 2.2.3) to be acceptable, on the basis that it adequately

identified all CCW system's non-safety-related SSCs that are added to the scope of license

renewal resulting firom the changed 10 CFR 54.4(a)(2) scoping methodology.

2.3.3.6.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant had omitted any SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition,Athe staff performed an independent assessment to

determine whether the applicant had identified all components that should be subject to an;

AMR. The staff did not identify any omissions. On the basis of its review, the staff concludes

that the applicant has adequately identified the components of the closed-cycle cooling water

system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has adequately identified thb c6mponents of the closed-cycle cooling water

system that are subject to an AMR, as required by 10' CFR 54.21 (a)(1).

2.3.3.7 Compressed Air System

2.3.3.7.1 Summary of Technical Information in the Application

In Section 2.3.3.7of the LRA, the applicant described the compressed air system. The

compressed air systemi includes the'ihstrument'air system, service air system, and portions of -

the rive'r water system that provide th& nitrogen backup supply to the service water pond waterlevel instruments. - -

The instrument air system supplies compressed air for pneumatic instruments and valves, as

well as for the service air system. The safety-related, air-operated valves and instruments that

are required to operate following design-basis events (e.g., main steam isolation valves,

pressurizer power-operated relief valves), and which'are normally supplied by instrument air,

are provided with backiup sources of either-air (accumulators) or compressed nitrogen. The

Appendix R'safe-shutdoWn analysis'also'relies'on"p6rtions of the instrument air system.

The service air system' routes compressed air supplied by the instrument air system to service

air outlets throughout the plant. -The service air system also contains emergency air

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compressors to support operation of the main steam atmospheric relief valves and turbinedriven AFW pump steam admission valves when the instrument air system is not available.

The river water system supplies makeup water to the service water pond. The only portions of.

the river water system that are in the scope of the compressed air system are the compressed .

nitrogen backup supplies to the service water pond water-level instruments.

In Table 2.2-1 c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the compressed air system components which are within the scope of license

renewal:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.7 of the LRA, the applicant listed the compressed air component types that are

within the scope of license renewal and subject to an AMR, including air accumulators, air

dryers, air receiver, closure bolting, filters (casing), piping, fluid traps, and valve bodies.

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 and FNP FSAR Sections 9.2.1 and 9.3.1. The staff

conducted its review using the evaluation methodology described in Section 2.3 of this SER, in

accordance with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function of the compressed air system in the LRA, in accordance with the

requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff then

evaluated, in accordance with the screening process described in Section 2.3 of this SER, that

the applicant had identified all passive and long-lived components subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.7 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff. issued several RAls to determine whether

the applicant had 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, dated April 22, 2004, and June 10, 2004.

RAI 2.3.3.7-1

License renewal boundary drawings D-170131 and D-200019 show compressed airl ines, which

are excluded from the scope of license renewal, continuing to provide 'air to essential

instruments," as referred to on drawings D-170473 and D-200020, Sheet 1. However, the

applicant did not provide drawings D-170473 and D-200020, Sheet 1, for the staff to review.

The staff requested that the applicant identify the essential instruments and clarify if any

intended functions performed rely on the compressed air supplied from these air lines.

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Alternatively, the applicant could provide drawings D-1 70473 and D-200020, Sheet 1, to allow

the staff to'determine whether the instrumehtation'air components on the lines to the essential

instruments have been appropriately'eicluded from the scope of license renewal and from an

AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1),

respectively.

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the continuation flags indicating "air

to essential instrurments" depict air service to components in the turbine building that are not

within the scope of license renewal. The essential instruments referred to by the continuation

flag (e.g., heater drain valves to the condenser, steam jet air ejector bypass valve, moisture

separator reheater (MSR) drain valves to the condenser) are essential for power production, but

are not required to suopprt 'a safety function or a'regulated event. - -

In response to the staff's request to identify whether intended functions are performed that rely

on the'c6mpressed air supplied from these air lines, the applicant stated that the compressed

air system is designed to preferentially isolate'portions of the system upon decreasing system

pressure to maintain air pressure to the auxiliary and containment buildings. Air-operated

valves V903 and V904 isolate the subject lines providing air to essential instruments upon

decreasing pressure in the compressed air system. Therefore, the applicant did not create

license renewal boundary drawings for drawings D-170473 or D-200020, Sheet 1, because they

do not contain any in-scope components;; -

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1 acceptable

because it (1) identifies the essential instruments'addressed in the RAI, (2) clarifies that the

essential Instrument components do not perform any intended function because these

components are essential for power production only, 'and (3) justifies the basis for. excluding the

supplied compressed air lines to the essential instruments from the scope of license renewal

and from an AMR,-in accordance with the requirements of 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1),'respectively. Therefore,,the staff considers RAI 2.3.3.7-1 resolved.

RAI 2.3.3.7-2

The staff requested the applicant to clarify' and explain why certain components and their

associated pipe segments and valves are excluded from the scope of license renewal and from

an AMR, while components in parallel trains are considered to be within the scope of license

renewal and subject to an AMR, as described below:

(a) License renewal boundary drawings D-170131 (Unit 1) and D-200019 (Unit 2) depict

that trains A and B 'of the air compressors and air receivers,'as well as their associated

piping to the check valve downstream of the receivers,.are excluded from the scope of

license renewal. However, these license renewal boundary drawings show that the train

C air compressor and air receiver, and their associated piping, are within the scope of

the license renewal. The staff requested that the applicant describe how t6e'above--

rmentioried corponents for trains A and B differ from the components for train C and

explainr how it considered these differences in the scoping and screening process for

trains A and B. ' - ,; - -

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II

(b) The staff requested that the applicant explain why piping and valves downstream of the :

check valves shown on license renewal boundary drawings D-170131 L and D-200019L

are considered within the scope of license renewal for trains A and B, if the air

compressors and receivers are not.

Applicant's Response and Staff's Evaluation

(a) By letter dated April 22, 2004, the applicant responded that the compressed air system

is not required for design-basis safe shutdown or to prevent/mitigate the consequences

of an accident. However; certain components of the compressed air system are in

scope for 10 CFR 54.4(a)(3), and in particular, the fire protection regulated event

(10 CFR 50.48).

In response to the staff's request to explain the differences considered in the scoping

and screening process for trains A, B, and C, the applicant stated that for train C, air

compressors and air receivers and dryers, as well as segments of the air distribution

system are relied upon for compliance with-10 CFR 50.48 and are therefore within the.

scope of license renewal. For both units, the A and B air compressors and air receivers,

as well as their associated piping to the check valves downstream of the receivers, are

not within the scope of license renewal because they are not relied upon for compliance

with 10 CFR 50A8.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-2a

acceptable because it explains that the train C air compressor is within the scope of

license renewal because of the fire protection regulated event (10 CFR 50.48), and the

trains A and B air compressors are excluded from the scope of license renewal because

they are not relied upon for compliance with the fire protection regulated event

(10 CFR 50.48). Therefore, the staff considers RAI 2.3.3.7-2a resolved..

(b) By letter dated April 22, 2004, the applicant stated that large portions of the air

distribution system downstream of these check valves are brought into the scope of -

license renewal because of no readily available means to isolate them from those

segments relied upon for compliance with 10 CFR 50.48. The applicant further stated

that all passive and long-lived compressed air system components that are in scope for

compliance with 10 CFR 50.48 were included in the screening process.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-2b.

acceptable because it adequately clarifies that the piping and valves downstream of the

check valves trains A and B are within the scope of license renewal, since there is no

readily available means to isolate them from the portions that are relied upon for

compliance with the fire protection regulated event (10 CFR 50.48). Therefore, the staff

considers RAI 2.3.3.7-2b resolved.

RAI 2.3.3.7-3

The staff requested that the applicant clarify whether the components of the dryer and/or

compressor assemblies are scoped and screened as complex assemblies. Regarding complex

assemblies, Table 2.1-2 of NUREG-1 800 states that "some structures and components, when

combined, are considered a complex assembly.... An applicant should establish the boundaries

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for each assembly by identifying each structure' and'co'rhpponent thatnmakes up the complex-'

assembly and determining whether or not each structure and component is subject to an AMR."

The staff requested that the applicant identif ythe'bouidaries of the dryer and air compressor'

assemblies to determine whether the subcornponents are within the scope of license-renewal

and subject to an AMR, in accordance withfthe r'equiremrents of '10 CFR 54.4(a) and

10 CFR 54.21 (a)(1), respectively. ' '

Applicant's Response and Staff's Evaluation'

By letter dated April 22, 2004, the applicant responded that the air compressors are classified

as'fully active components and are specifically excluded from the requirements of-an'-AMR in

the text of 100FR 54.21(a)(1)(1). The applicant added that based on NEt 95:10, Revision 3,

which is endorsed by the NRC in RG 1.188, uStandard Format'and Content for Applications to

Renew Nuclear Power Plant Operating Licenses," states that the air compressors do not

require an AMR. The boundary of the air o'mpressrs begins from the entrance of the inlet

piping to the compressor and ends wherd the discharge piping joins the air compressors. This

is consistent with the guidance in Table 2.1-2 in NUREG 1800 pertaining to complex

assemblies. The staff finds the applicant's response related to the air compressor assemblies

acceptable because the applicant adequately justif ies the exclusion of the air compressors from

an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

For the air dryers,'the applicant stated thatfthe air dryer assemblies are complex assemblies.

Consistent with the requirements-of complex assemblies; the air dryer assemblies were broken

down into'individual components'and were e'valu'ated separately. The applicant furtherexplained that the air dryer skids (Ni P19F001 NB 'and Ni P18FOO1 [should be N1 P18F501])

shown on the license renewal boundary drawing Dl 70131 L, Sheets 3 and 4, c6ntain passive'

pressure boundary components that were included in the AMR. The applicant stated that in

LRA Table 3.3.2-7, the air dryer subcomponents were rolled up into a single component type,

"air dryer," to allow the aging management strategy for these passive subcomponents to be

effectively represented. The applicant also stated that the boundary of the air dryer component

type begins where the 3" HBD-433 line enters the dryer skid and ends where the line leaves the

skid.

The staff found this portion of the applicant's response unacceptable because the staff

observed that the license renewal boundary drawings showed the air dryer skids to be mounted

on separate skids, rather than on a single skid. Furthermore, in the tables provided by the.

applicant in its response to RAI 2.2-2, the air dryer component type was defined as "air dryer of

the compressed air system. ^Only the shelf 'of'the'air dryer is considered passive and long- '

lived." In addition, LRA Table'3.3.2-27 did not provide afik details of the air dryer

subcomponrients. In regard to' the boundary'of the&air dryers; the staff found that the applicant's

response differed from the boundaries'shown oh the license renewal drawings.

During a telephone'conference on May 2472004, between the applicant and the NRC staff, the

applicant agreed to revise its response to RAI 2.3.3.7-3 to define the air dryer subcomponents

and the boundary of air dryer aassemrblies.- By letter-dated June'10, 2004, the applicant's

revised responqse stated that theair dryer'assemblies'are complex active assemblies. The air:

dryer skids contain passive pressure boundary-subcomponents, as shown o 'license renewal

boundary drawings D-170131L, Sliebt 3 (f6fr'ir dryers N1 P19FO1A7and F001 B),' and D-''

170131L, Sheet 4 (for N1P18F5O1A). The passive subcomponents are piping, valve bodies,

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p

filter casings, the air dryer casing, the purge exhaust mufflers, and the restricting orifices. The

subcomponents are comprised of carbon steel. The applicant has chosen "air/gas (wetted)" as

the interior environment for. all of the subcomponents on the skid. The exterior environment of

all the subcomponents is-"inside." In LRA Table 3.3.2-7, the applicant rolled the

subcomponents up into a single component type, "air dryer," to allow the aging management

strategy for these passive subcomponents to be effectively represented.

In response to the staff's request to identify the boundaries of the air dryer component type, the

applicant stated the following:

* On license renewal boundary drawing D-170131 L, Sheet 3, the boundary of the air dryer

component type begins where the 3' HBD-261 line' enters the dryer skid and ends

where the 3" HBD-262 line leaves the skid.

* On license renewal boundary drawing D-170131 L, Sheet 4, the boundary of the air dryer

component type begins where the 3" HBD-433 line enters the dryer skid and ends

where the line leaves the skid.

Based on its review, the staff finds the applicant's revised response to RAI 2.3.3.7-3 acceptable

because it (1) clarifies that the applicant had scoped and screened the components of the dryer

and/or compressor assemblies as complex assemblies, (2) identifies the passive

subcomponents of the air dryer component type that are within the scope of license renewal, (3)

identifies the boundaries of the air dryer and its subcomponents subject to an AMR and, (4)

identifies the boundaries of the air compressor assemblies and justifies their exclusion from an

AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1). Therefore, the staff

considers RAI 2.3.3.7-3 resolved.

RAI 2.3.3.7-4

License renewal boundary drawing D-1 70131 L shows a Y-strainer (noted as "strainer by field")

within the scope of license renewal. Strainers provide the intended function of debris protection

and pressure boundary and are passive and long-lived components. The staff requested that

the applicant justify the exclusion of the Y-strainer from an AMR, in accordance with the

requirements of I OCFR 54.21 (a)(1).

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the strainer body performs the

intended function of pressure boundary and is screened as carbon steel pipe. The strainer

element is within the scope of license renewal and provides the intended function of debris

protection. The applicant concluded that LRA Tables 2.3.3.7 and 3.3.2-7 inadvertently omitted

the strainer element. In its response, the applicant provided tables for the addition of this

component to LRA Table 2.3.3.7 and to the corresponding LRA Table 3.3.2-7.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-4 acceptable

because it adequately clarifies that the strainer body and strainer element are within the scope

of license renewal and subject to an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively. Therefore, the staff considers RAI

2.3.3.7-4 resolved.

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2.3.3.7.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant had omitted any SSCs thatsli6uld be within the scope of license renewal.

The staff did not find any omissions. 'In addition, Pie staff performed an'independent ;

assessment to determine whether the applicant' had identified all components that should be -

subject to an AMR. The staff found no omissions. On'the basis of its review, the staff

concludes that the applicant has adequately' identified the components of the compressed air

system that are within the scope of license'renewl, as required by 10 CFR 54.4(a), and that

the applicant has adequately identified the 'components of the compressed air system that are

subject to an AMR, as required by 10 CFR 54.21(a)(1).' -

2.3.3.8 Chemical and Volume Control System

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 CVCS. For the purposes of the

application, the CVCS includes the non-ECCS portions of the CVCS and the boron thermal

regeneration system (BTRS).

The CVCS maintains the required inventory in the RCS by maintaining the programmed water

level in the pressurizer. The CVCS also provides a continuous feed and bleed of reactor

coolant water which is used in the control of 'water 6hernistry conditions, activity level, and

soluble chemical neutron absorber concentration and makeup. The CVCS also provides seal

water inje6tion flow to the RCPs. Portions of'the system contain borated water at higher

concentration than the RCS for use in maintaining the reactor shutdown margin. The system

includes provisions for recycling reactor grade 'water. Portions-of the CVCS function as part of

the ECCS to provide injection flow to the RCS'durinrg postaccident injection and recirculation.

The BTRS is occasionally used as deborating demineralizers to reduce reactor coolant boron

concentration towards the end of core life.-'Although not typically used for this purpose at FNP,

the BTRS is designed to provide load-following capabilities by varying the RCS boron,

concentration to compensate for xenon tranrsients and other reactivity changes, which occur - -

when the reactor power level is changed. 'The RCS boron concentration is changed by storing

boron in, or releasing boron fromni,'thermially regenerable deminerdlizers. The function of this

system is not safety related. The BTRS is-installed for economic reasons only. -The CVCS

performs 'safety-related boration and dilution "H6iW-ever, when in use, the BTRS forms part of

the letdown path for the CVCS and is a high-energy line.

High-energy line break (HELB) compartment/room pressure sensors are provided in areas

affected by a rupture of a CVCS letdown line or a BTRS line to initiate letdown line isolation.

The compartment/room pressure sensors are addressed separately as part of the HELB

detection system boundary. ' ' ' - --

In Table 2.2-1c of the LRA, the applicant identified the following criteria it used to determine the

SSCs that are within the'scope of license rrenewal for the CVCS:

* safety-related (10 CFR 54.4(a)(1)) :'

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

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a

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.8 of the LRA, the applicant listed the CVCS component types that are within the

scope of license renewal and subject to an AMR, including'closure b6lting; regenerative heat

exchanger (channel heads); regenerative heat exchanger (shells); regenerative heat exchanger

(tubes/tubesheet); letdown, excess letdown, and RCP seal, water heat exchangers (channel'

head); letdown, excess letdown, and RCP seal water heat exchangers (shell), letdown, excess

letdown, and RCP seal water heat exchangers (tubes/tubesheet); boron thermal regeneration

chiller (channel head); boron thermal regeneration chiller (tubes/tubesheet); boron thermal

regeneration moderating and reheat heat exchanger (channel head and shell); boron thermal

regeneration moderating and reheat heat exchangers (tubes/tubesheet); demineralizers

(pressure retaining components); filters (casing); letdown orifices; piping; boric acid transfer

pump casings; boric acid transfer pump casings; boric acid tanks; volume control tank; and

valve bodies.

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8 and FNP FSAR Sections 9.3.4.1 and 9.3.4.2. The staff

conducted its review using the evaluation methodology described in Section 2.3 of this SER, in

accordance with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff reviewed the FSAR for any functions delineated under

10 CFR 54.4(a) that the applicant had not identified as intended functio'nis in the LRA, and to

verify that the SSCs with such functions will be adequately managed so that the component

intended functions will be maintained consistent with the CLB for the period of extended

operation. The staff did not identify any omissions. The staff then reviewed the LRA to verify

that the applicant had not omitted passive or long-lived components fro'm an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant had identified all SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent'assessment to

determine whether the applicant had omitted any components that should be subject to an

AMR., The staff did not identify any omissions. On the basis of its review, the staff concludes

that the applicant has adequately identified the CVCS 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 CVCS components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.8.3 Conclusion

During its review of 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 the

chemical and volume control components.. The staff concludes that the applicant has

adequately identified the chemical and volume control 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 chemical and volume control components that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

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2.3.3.9 Control Room Area Ventilation System

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 control room area ventilation system.

The control room area ventilation system provides Ventilation, heating, cooling, filtrdatio'n; and air

intake and exhaust isolation during normal operation nand following a design-basis accident.

The system consists of two parts, an e'nvironmental control system and an air cleanup system.

The environmental control system operates continually during normal and emergency

conditions. The air cleanup system normally operates only during emergency conditions. The

control room area ventilation system has three operational modes-normal ventilation,

emergency pressurization, and emergency recirculation. The safety-related operating modes

are emergency recirculation and emergency pressurization. This system maintains the control

room environment within design limits and ernsures compliance with the control room dose

requirements of Appendix A to 10 CFR Part 50,' General Design Criterion 19 (GDC), "Control'

Room."

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria'it usedto determine the SSCs that are within the scope of license renewal for the control room area

ventilation system:

* safety-related (10 CFR 54.4(a)(1))

* fire protection (10 CFR 54.4(a)(3))

In Table 2.3.3.9 of the LRA, the applicant listed the control room area ventilation system

component types that are within the scope of license renewal and subject to an AMR, including

closure bolting, compressible joints and seals, cooling coils (heating, ventilation, and air

conditioning (HVAC) refrigerant coils and fins),-'dbcts and fittings, equipment frames and'

housings, fire dampers (frames and housings only), flexible connectors, piping, and valve

bodies.

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 and FNP FSAR Sections 6.4 and 9.4.1 to determine'

whether the applicant identified the control r6om area ventilation 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 Section 2.3 of

NUREG-1 800.

In its evaluation, the staff reviewed the FSAR to determine if the applicant had omitted any

safety-related system functions as an intended 'function of the control room area ventilation

system in LRA, in accordance with the requirements of 10 CFR 54.4. The staff did not identify

any omissions. ' ''

The staff also selected system functions described in the FSAR that were'required by

10 CFR 54.4 to verify that the applicant had not omitted components having intended functions

from the scope of the Rule. The staff focused on components that the applicant had identified

as being subject to an AMR to determine if any components were'omitted.

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To verify that the applicant had identified the components of the control room area ventilation

system 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 P&l drawings to the

system drawings and system descriptions in the FSAR to ensure that the referenced P&l

drawings were representative of the control room area ventilation system. The staff then

reviewed the referenced P&l drawings to verify that the applicant had included those portions of

the control room area ventilation system thatfmeet the scoping requirements of 10 CFR 54.4

within the scope of license renewal and identified them as such in LRA Section 2.3.3.9. The

staff also determined that the applicant had identified all control room area ventilation 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's review of LRA Section 2.3.3.9 did not identify areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, the staff did not issue any RAls to determine whether the applicant has properly

applied the scoping criteria of 10 CFR 54.4 and the screening criteria of 10 CFR 54.21.

2.3.3.9.3 Conclusion

During its review of 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 the

control room area ventilation components. The staff concludes that the applicant has

adequately identified the control room area ventilation 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 control room area ventilation components that are subject to an AMR, as required

by 10 CFR 54.21 (a)(1).

2.3.3.10 Auxiliaty and Radwaste Area Ventilation System

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 auxiliary and radwaste area

ventilation system. For the purpose of license renewal, the auxiliary a'nd radwaste area

ventilation system includes the PRF system, engineered safeguards room air cooling system,

radioactive waste ventilation and filtration system, nonradioactive ventilation system, and spent

fuel pool ventilation and filtration system.

The PRF system can be aligned to operate under either of two accident modes, the post-LOCA

operating mode or the fuel-handling mode. The PRF system limits releases to the environment

of radioisotopes from ECCS leakage into the penetration rooms during accident (post-LOCA)

conditions. The PRF system' maintains a negative pressure on the room boundary to ensure

leakage is into the room and filtered before being exhausted. The PRF system also provides

safety-related ventilation and filtration for the SFP area. The applicant addressed the room

pressure sensors assigned to the PRF system that detect elevated room pressure as part of the

HELB detection system.

The engineered safeguards room air cooling system maintains the ambient temperature within

analyzed limits in rooms containing designated equipment important to safety.

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The radioactive waste ventilation and filtration system provides a suitable environment for

personnel and for' equipment operation in auxiliary' building areas with the' potential for

radioactive contamination. The system also controls and directs potentially contaminated air to

the vent stack via filtration units. The fire dampers in this system bring portions of the system

within the scope of license renewal.

The nonradioactive ventilation system provides a suitable environment for personnel and for

equipment operation in portions of the auxiliary building containing systems which are normally

not radioactively contaminated. Battery room exhaust continuously removes combustible

gases. This system is also within the scope of license renewal because of the system's fire

dampers. '

The spent fuel pool ventilation and filtration system provides normal ventilation and filtration for

the SFP area. The system is designed to maintain a suitable environment foe'personnel and for

equipment operation in the spent fuel areas, remove water vapors above the SFP to improve.

visibility, filter SFP area exhaust air during normal operation, and maintain a slightly negative

pressure in the SFP area with respect to the surrounding areas and the outside. Following a

fuel-handling accident,'the spent fuel pool ventilation and filtration 'system isolates'and realigns

to route the exhaust air from the SFP area to the PRF system to ensure proper filtration and

monitoring of the exhaust air.

The applicant has conservatively included the plant vent stack noble gas radiation monitor,

which is required to comply with the guidelines of RG '1.97, "Instrumentation for Light-Water- ;

Cooled Nuclear Power Plants To Assess Plant and Environs Conditions During and Following

and Accident," Revision 3, (Category 2 variable), ir'the scope of license renewal as part of the

auxiliary and radwaste area ventilation system.

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the SSCs that are within the scope of license renewal for the auxiliary and

radwaste ventilation system:

* safety-related (10 CFR 54.4(a)(1))

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.10 of the LRA, the applicant listed the auxiliary and radwaste area ventilation

system component types that are within the scope of license renewal and subject to an AMR,

including closure bolting, compressible joints and seals, ducts and fittings, equipment frames

and housings, cooling units (fan/coil fins only), fire dampers (frames and housings only), flexible

connectors, flow orifice/element, piping,'pilot tube,' and valve bodies.'

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 and FNP FSAR Sections 6.2.3, 9.4.2 and 9.4.3 to

determine whether the applicant identified the auxiliary and radwaste area ventilation system

comp6nents 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 conducted its review in accordance with Section

2.3 of NUREG-1800.

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a

In its evaluation, the staff reviewed the FSARs to determine if the applicant had omitted any

safety-related system functions as an intended function of the' auxiliary and radwaste area

ventilation system in the LRA, in accordance with the requirements of 10 CFR 54.4. The staff

did not identify any omissions.

The staff also selected system functions described in the FSARs that were required by 10 CFR

54.4 to verify that the applicant had not omitted components having intended functions from the

scope of the Rule. The staff focused on components that the applicant had not identified as

being subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the auxiliary and radwaste area

ventilation system 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 P&l

drawings to the system drawings and system descriptions in the FSAR to ensure that the

referenced P&l drawingswere representative of the auxiliary and radwaste area ventilation

system. The staff then reviewed the referenced P&l drawings to verify that the applicant had

included those portions of the auxiliary and radwaste area ventilation system that meet the

scoping requirements of 10 CFR 54.4 within the scope of license renewal and identified them

as such in LRA Section 2.3.3.10. The staff also determined that the applicant had identified all

auxiliary and radwaste area ventilation 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's review of the LRA Section 2.3.3.10 did not identify areas in which it needed

additional information to complete the evaluation of the applicant's scoping and screening

results. Therefore, the staff did not issue any RAls to determine whether the applicant had

properly applied the scoping criteria of 10 CFR 54.4 and the screening criteria of 10 CFR 54.21.

2.3.3.10.3 Conclusion

During its review of 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 the

auxiliary and radwaste area ventilation system components. The staff concludes that the

applicant has adequately identified the auxiliary and radwaste area ventilation 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 auxiliary and radwaste area ventilation system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.11 Primary Containment Ventilation System

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 primary containment ventilation

system. For the purposes of license renewal, the primary containment ventilation system

includes the containment cooling system and the containment purge system.

The containment cooling system removes heat from containment during normal operation and

shutdown, and functions as one of the postaccident containment heat removal systems. Each

containment is equipped with four containment cooler units. Each air cooler consists of a

housing equipped with a fan and finned tube coils supplied by water from the service water

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system. Dropout plates with release mechariisms;actuated by fusible links are provided at the

discharge of the containment coolers. Thes plates'fall away t6uncouple the cooler discharge

from the distribution ductwork after a LOCA.;'

The containment purge system provides ventilation and filtration'to allow access to the

containment after shutdown. During normal power operation, the main purge valves are

isolated and the mini-purge portion of the system provides for continuous ventilation and

filtration of th'e containmrent at mosphere. Safety-related reasons for venting containment during

normal power operations include controlling containment pressure and reducing airborne

radioactivity. ' '"

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a)criteria it used

to determine the SSCs that are within the scope of license renewal for the primary containment

ventilation system:

. safety-related (10 CFR 544(a)(1)) non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3));'

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.11 of the LRA, the applicant listed the primary containment ventilation system

component types that are within the scope of license renewal and subject to an AMR, including

closure bolting, compressible joints and seals, ducts and fittings, equipment frames and,

housings, cooling coil (fins only), fire dampers (frames and housings only), flexible connectors,

flow orifice/element, piping, pitot tube, and valve bodies. -

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 and FNP FSAR Sections 6.2.2 and 6.2.3 to determine

whether the applicant identified the primary containment ventilation system components within

the scope of license renewal and subject to an AMR, in accordance with 1 0 CFR 54.4 and 1 0

CFR 54.21 (a)(1). The staff conducted its review in accordance with Section 2.3 of

NUREG-1 800. -

In its evaluation, the staff reviewed the FSARs to determine if the applicant had omitted any

safety-related system functions as an intended function 'of the primary containment ventilation

system in the LRA, in accordance with the requirements of 10 CFR 54.4. The staff did not

identify any omissions. ' '

The staff also selected system functions described in the FSARs that were required by 10 CFR

54.4 to verify that the applicant had not omitted components having intended functions from the

scope of the Rule. The staff focused on components that the applicant had not identified as

being subject to an AMR to determine if any components were omitted.:.

To verify that the applicant identified the comp6nents of the primary, containment ventilationsystem that are withiri the scope'6f license'renewal and subject to an AMR,-in accordance with

10 CFR 54.4 and 1 0 CFR 54.21 (a)(1), the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the FSARs to ensure that the referenced P&l

drawings were representative of the primary containment ventilation system. The staff then

'2-81
a

reviewed the referenced P&l drawings to verify that the applicant had included those portions of

the primary containment ventilation system that meet the scoping requirements of 10 CFR 54.4

within the scope of license renewal and identified them as such in LRA Section 2.3.3.11. The

staff also determined that the applicant had identified all primary containment ventilation 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's review of the LRA Section 2.3.3.11 did not identify areas in which it needed

additional information to complete the evaluation of the applicant's scoping and screening

results. Therefore, the staff did not issue any RAls to determine whether the applicant had

properly applied the scoping criteria of 10 CFR 54.4 and the screening criteria of 10 CFR 54.21.

2.3.3.11.3 Conclusion

During its review of 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 the

primary containment ventilation system components. The staff concludes that the applicant has

adequately identified the primary containment ventilation 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 primary containment ventilation system components that are subject to an AMR,

as required by 10 CFR 54.21(a)(1).

2.3.3.12 Yard Structures Ventilation System

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 yard structures ventilation system.

For the purposes of license renewal, the yard structure ventilation system includes the HVAC

systems serving the various yard structures at the plant. The portions of the yard structures

ventilation system in the scope of license renewal are at the service water intake structure

(SWIS) and at the diesel generator building.

The SWIS and diesel generator building ventilation systems provide heating and ventilation to.

their associated structures to provide suitable environments for personnel and for equipment

operation during normal, as well as emergency, conditions. The SWIS ventilation system also

functions to minimize hydrogen concentration in the safety-related battery rooms.

In Table 2.2-1c of the LRA, the applicant identified the following criteria it used to determine the

SSCs that are within the scope of license renewal for the yard structures ventilation system:

* safety-related (10 CFR 54.4(a)(1))

* fire protection (10 CFR 54.4(a)(3))

* station blackout (10 CFR 54.4(a)(3))

In Table 2.3.3.12 of the LRA, the applicant listed the yard structures ventilation system

component types that are within the scope of license renewal and subject to an AMR, including

closure bolting, ducts and fittings, equipment frames and housings, and fire dampers (frames

and housings only).

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2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 and FNP FSAR Sections 9.4.5 and 9.4.7 to determine

whether the applicant had identified the yard structures ventilation system components within

the scope of license renewal and subject to an AMRin accordance With 10 CFR 54.4 and 10

CFR 54.21 (a)(1). The staff's conducted its'review in accordance with Section 2.3 of

NUREG-1800.

In its evaluation, the staff reviewed the FSARs to determine if the applicant had omitted any

safety-related system functions as an intended function of the yard structures ventilation system

in the LRA, in accordance with'the'requirements'of 10 CFR 54.4. The'staff did not identify any

omissions.

The staff also selected system functions described in the FSARs that were required by 10 CFR

54.4 to verify that the applicant had not omitted components having intended functions from the

scope of the Rule. 'The staff focused on components the applicant had not identified as being

subject to an AMR to determine if any components were omitted.

To determine that the applicant identified the components of the yard structures ventilation

system that are within the scope of license renewal and subject to an AMR, in accordance with

1 OCFR 54.4 and 10 CFR 54.21 (a)(1), the staff compared the referenced P&l drawings to the

system drawings and system descriptions in'the FSARs to ensure that the referenced P&l

drawings were representative of the yard structures ventilation system. The staff then reviewed

the referenced P&l drawings to verify that the applicant had included those portions of the yard

structures ventilation system that meet the scoping requirements of 10 CFR 54.4 within the - scope of license renewal and identified them as such in LRA Section 2.3.3.12. The staff also

determined that the applicant had identified all yard structures ventilation 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's review of the LRA Section 2.3.3.12 did not identify areas in which it needed

additional information to complete the review'of the applicant's scoping and screening results.

Therefore, the staff did not issue any RAls to determine whether the applicant had properly

applied the scoping criteria of 10 CFR 54.4 and the screening criteria of 10 CFR 54.21.

2.3.3.12.3 Conclusion

During its review of 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 the -

yard structures ventilation system components. The staff concludes that the applicant has

adequately identified the yard "structures ventilation 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 yard structures ventilation' syitdm c6mponents that are subject to an AMR, as

required by I10 CFR 54.21 (a)(1).

. . .. ..- .

; . i . . , 

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2.3.3.13 Fire Protection

2.3.3.13.1 Summary of Technical Information in the Application

In Section 2.3.3.13 of the LRA, the applicant described the fire protection system. The fire

protection system protects plant personnel and equipment in the event of a fire to ensure safe

shutdown of the plant and to minimize the risk of a release of radioactive material to the

environment. Fire protection features include fire suppression, fire detection and actuation, and

fire barriers. The applicant screened the fire detection and actuation portion of the system as

part of the electrical and l&C system. The applicant screened the fire dampers as part of the

assigned HVAC system. Other passive fire barriers are screened as part of structures.

The fire protection system includes both manual (use of hoses, portable extinguishers, fixed

systems by plant personnel) and automatically actuated fire suppression features. Depending -

on the area protected, the suppression system employs extinguishing agents consisting of

water, carbon dioxide, and/or Halon. The water suppression systems include the stbrage tanks,

fire pumps (including the diesel-driven fire pump fuel oil and other auxiliary systems), yard

mains, hose stations, and sprinkler systems. The carbon dioxide and Halon suppression

systems include supply tanks or cylinders and distribution piping. Miscellaneous mechanical

fire protection features, such as self-contained breathing apparatus, are also included.

Portable fire protection equipment, such as fire hoses, fire extinguishers, C02 bottles, and selfcontained breathing apparatus air bottles, is not subject to an AMR because this equipment is

considered short-lived, replaced on condition, and exempted from AMR consistent with the

treatment of consumables.

In Table 2.2-1 c of the LRA, the applicant identified the 10 CFR 54.4(a)(3) fire protection

regulated event criterion as the scoping criterion used for the fire protection system

components which are within the scope of license renewal.

In Table 2.3.3.13 of the LRA, the applicant listed the fire protection component types that are

within the scope of license renewal and subject to an AMR, including closure bolting, fire.

hydrants, flexible connectors, flow orifice/element, fusible links and sprinkler head bulbs, hose

station nozzles and hose connections, water system piping and valve bodies,. gas system piping

and valve bodies, fuel oil system piping and valve bodies, pump casings, sight glasses, spray

shield, sprinkler heads, strainers (element), strainers (shell), tank protective fiberglass cover,

water system tanks, gas system tanks, fuel oil system tanks, and thermal insulation (CO2 tank).

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 and FNP FSAR Section 9.5.1. The staff conducted its

review using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function of the fire protection system in the LRA, in accordance with the requirements

of 10 CFR 54.4(a). The staff then evaluated, in accordance with the screening process

described in Section 2.3 of this SER, that the applicant had not omitted any passive and long2-84
lived components from an AMR, in accordance' with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.13 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping'and screening results.

Therefore', by letter dated March 23, 2004, the-staff issued several RAls to determine whether

the applicant had 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, dated April 7, 2004.

RAI 2.3.3.13-1

(a) License renewal boundary-drawing D-170384 shows low-pressure carbon dioxide

systems on the 155'0" level of the' Unit'l tdrbine building excluded from the scope of

license renewal. The' system located between'E-9 and G-9 on the drawing is not

identified. License renewal boundary drawing D-200152 identifies low-pressure carbon

dioxide systems in the Unit 2 turbine-building and excludes the load centers and 4160-V

switchgear from the'scope of license renewal. 'The'staff requested that the applicant

identify the unlabeled system in Unit 1 and justify the exclusion of these systems in Units

1 and 2 from the scope of license renewal, in accordance with the requirements of

10 CFR 54.4(a).

(b) License renewal boundary drawing D-170385 shows the Unit 1 high-pressure carbon

dioxide systems in the river water switchgear excluded from the scope of license

renewal. 'The staff requested that the applicant justify the exclusion of these systems

from the scope of license renewal, in accordance with the requirements of 10 CFR

54.4(a).'

(c) License renewal boundary drawings'D-1 70386 and D-205021 identify the Unit 1 Halon

fire protection systems'and Unit 2 Halon fire protection systems.. Both drawings include

the fire protection system in the commnunication's-room and exclude the systems in the

computer room'and control syst6m cabinet room. The staff requested that the applicant

justify the exclusion of the fire protection systems in the computer room and control

system cabinet room from the scope of license renewal, in accordance with the

requirements of 10 CFR 54.4(a).

(d) License renewal boundary drawing D-508526L identifies the fuel oil systems for the

diesel engine fire'pumps. The drawin'g shows the license renewal boundary at the

flexible supply and return line conn6ction. 'The flexible fuel lines, the fuel filters, and fuel

pumps are excluded from the'sc6pe of license renewal. -The staff requested that the

'applicant justify the exclusion of these components from the scope of license renewal, in

accordance with the requirements'of 10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation

(a) In a letter dated April 7, 2004, the applicant responded that the only carbon dioxide

SSCs in the turbine building within the scope of license renewal are those associated

with the low-'pressure bulk carboi -dioxide storage and supply system that supplies

carbon dioxide to both the'Unit 1 'ad Unit 2 auxiliary building carbon dioxide systems.

The auxiliary building carbon dioxide fire suppression equipment is relied upon to protect

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l

safety-related SSCs and ensure safe shutdown in the event of a fire as part of FNP's

compliance with 10 CFR 50.48.

The Unit 1 turbine building low-pressure carbon dioxide SSCs on the 155'0" elevation

shown on the drawing exist for commercial property protection and are excluded from

the scope of license renewal because the applicant does not rely on the fire suppression

capability for compliance with 10 CFR 50.48. License renewal boundary drawing

D-1 70384L is included as a boundary drawing because a portion of the in-scope

boundary from another drawing continues on this drawing up to and including the

isolating device.

In response to the staff's request to identify the system on license renewal boundary

drawing D-170384L, the applicant further stated that the system located between E-9

and G-9 on the license renewal boundary drawing is the carbon dioxide suppression

system for the nonsafety-related 4-kV switchgear bus 1 E (System 1T-14). The 4-kV

switchgear buses and 600-V load center buses that are being fire protected by the

carbon dioxide SSCs on the 155'0" elevation are nonsafety related and not relied upon

for safe shutdown. Therefore, they are excluded from the scope of license renewal.

In response to the staff's request to justify the exclusion of the low-pressure carbon

dioxide systems in the Unit 2 turbine building, the load centers, and the 4160-V

switchgear from the scope of license renewal, the applicant stated that the carbon

dioxide SSCs for the load center buses and 4-kV switchgear buses in the Unit 2 turbine

building are not relied upon for compliance with 10 CFR 50.48. License renewal

boundary drawing D-200152L is included because a portion of the in-scope boundary

from another drawing continues on this drawing up to and including the isolating device.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-1a

acceptable because it identifies the unlabeled system in Unit, 1 and justifies the

exclusion of the low-pressure carbon dioxide systems in the Unit 1 and Unit 2 turbine

building, as well as the Unit 2 load centers and 4160-V switchgear, from the scope of

license renewal, in accordance with the requirements of 10 CFR 54.4(a). Therefore, the

staff considers RAI 2.3.3.13-1 a resolved.

(b) In a letter dated April 7, 2004, the applicant responded that the river water system is

located remotely from the plant's safety-related structures (over 2000 feet from the

auxiliary buildings and from the pond) and houses the river water pumps and related

equipment, none of which are required for safe shutdown (including in the event of a

fire) or to mitigate any accident. The portions of the river water system within the scope

of license renewal (i.e., the service water pondwater-level instruments) described in LRA

Section 2.3.3.5 are located at the service water pond and not at or in proximity of the

river water structure. The applicant excluded the carbon dioxide systems located in the

river water intake structure for suppressing a fire in the switchgear from the scope of

license renewal because the equipment is not relied upon for compliance with 10 CFR

50.48.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-1 b

acceptable because it justifies the exclusion of the Unit 1 high-pressure carbon dioxide

systems in the river water switchgear from the scope of license renewal, in accordance

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with the requirements of ,10 CFR 54.4(a). Therefore,' the staff considers RAI 2.3.3.13-1b

resolved.

(c) In a letter dated April 7, 2004, the applicant responded that the Halon fire protection

systems for the control system cabinret roomis for Unit 1 and Unit 2 are located in rooms

235 and 2235, respectively. The' Hal6n fire protection systems for-the computer rooms

for Unit 1 and Unit 2 are located in rooi's 201 and 2201, respectively. The applicant

further stated that the carbon dioxide hose reels are located in rooms outside of, but

near to, the computer rooms. For r6or'n'is 235 and '2235, SNC credits the hose stations,

and for rooms 201 and 2201, SNC credts C02 hose reels. The Halon fire protection .

systems for the control system cabinet rooms and computer rooms for both FNP units

remain in place, but are not relied upon for 10 CFR 50.48 compliance. Therefore, the

applicant excluded these systems from the scope of license renewal.

Based on its review,- the staff finds the applicarit's response to RAI 2.3.3.13-1 c

acceptable because it justifies the exclusion of the Halon fire protection systems in the,

computer room and control system cabinret room from the scope of license renewal, in

accordance with the'requirements of 10 CFR 54.4(a). Therefore, the staff considers

RAI 2.3.3.13-1c resolved.

(d) By letter dated April 7, 2004, the applicant responded that the fuel oil systems for the

diesel engine fire pumps are identified on license renewal boundary drawing D-508562L

and are located on the fire pump diesel skid. The applicant considers these systems to

be an integral part of the diesel endine active assembly and they should have been

shown within the scope of license 'renewal on the license renewal boundary drawing.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-1d

acceptable because it concurs that the fuel oil systems for the diesel engine fire pumps

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

10 CFR 54.4(a)., Therefore, the staff considers RAI 2.3.3.13-1d resolved.

RAI 2.3.3.13-2

The FNP FSAR identifies the cable fire barrier, such as Kaowool,'needed to meet the

requirements of Appendix R to 10 CFR 50.48. However, neither LRA Section 2.3.3.13 nor

Section 2.4 reference these fire barriers. The staff requested that the applicant identify where it

addressed these barriers in the LRA, and if they are within the scope of license renewal and -

subject to an AMR. If not, the staff requested that the applicant justify their exclusion from the

scope of license renewal and'from'an AMR, in accordance with the requirements of .10 CFR

54.4(a) and 10 CFR 54.21 (a)(1), respectively. -

Applicant's Response and Staff's Evaluation - .- . . . .. I 

By letter dated April 7, 2004, the applicant responded that it addressed cable fire barriers, such

as Kaowool and Maranite, in th6 scoping for fire barriers credited in the CLB. The applicantsubjected these barrier materials to'a comrnodity-based AMR and determined that they do not

have aging effects requiring management. 'The'applicant uses Kaowool as a fire barrier ;

material in the auxiliary building and SWIS only. Maranite is utilized in the seismic Category 1

auxiliary building, diesel generator building, and SWIS.

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The applicant further stated that LRA Tables 2.4.2.1, 2.4.2.2, and 2.4.2.5 inadvertently omitted

fire wraps and fire stops as a component type subject to an AMR. Correspondingly, LRA

Tables 3.5.2-2, 3.5.2-3 and 3.5.2-6 should have included the AMR summary.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-2 acceptable

because it explains that cable fire barriers are addressed in the scoping for fire barriers' credited

in the CLB. Further, the applicant concurs that the cable fire wraps 'and fire' stops are within the

scope of license renewal and subject to an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively. Therefore, the staff considers RAI

2.3.3.13-2 resolved.

RAI 2.3.3.13-3

The FNP FSAR states that in certain areas of the plant, such as the cable spreading room,

structural steel members'are provided with sprayed-on fire resistant materials. However, the

applicant does not discuss these materials in either the scoping and screening sections or the

AMR sections of the LRA. The staff requested that the applicant confirm that the fire-resistant

coatings for structural steel members are within the scope of license renewal and subject to an

AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1),

respectively.

Agplicant's Resgonse and Staff's Evaluation

By letter dated April 7, 2004, the applicant responded that the fire-resistant materials for

structural steel protection are used in the auxiliary building (cable spreading room), as well as

on the doors at the diesel generator building's entrance to the cable tunnels. They are within

the scope of license renewal and subject to an AMR. The applicant further, stated that LRA

Table 2.4.2.1 should have identified these coatings as component types subject to an AMR.

Correspondingly, LRA Table 3.5.2-2 should have included the AMR sum mary.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-3 acceptable

because it concurs that the fire-resistant coatings for structural steel members are within the

scope of license renewal and subject to an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively. Therefore, the staff considers RAI

2.3.3.13-3 resolved.

2.3.3.13.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant omitted any SSCs that should be within the scope of license renewal.'

The staff did not identify any omissions. In addition, the staff performed an independent

assessment to determine whether the applicant had omitted any components that should be

subject to an AMR. The staff found no omissions. On the basis of its review, the staff -

concludes that the applicant has adequately identified the components of the fire protection

system that are within the scope of license renewal, as required by 10 CFR 54:4(a), and that

the applicant has adequately identified the components of the fire protection system that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.14 Diesel Fuel Oil System ; ;-

2.3.3.14.1 Summary of Technical Information in'the Application

In Section 2.3.3.14 of the LRA, the applicant described the diesel fuel oil system.' The diesel

fuel oil system'supplies fuel oil to the EDGs,166luding the AAC-designated diesel (SBO)L The'

diesel fuel oil system is a support system to the EDG system that is necessary to support

continued operation of the diesel generators. The EDGs are supplied from dedicated day tanks

in the diesel generator building, which in turn are replenished from larger, underground storage

tanks.

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the diesel fuel oil system components within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1)),

* fire protecti6n (10 CFR 54.4(a)(3))

station blackout (10 CFR 54.4(a)(3))'

In Table'2.3.3.14 of the LRA,'the applicant listed the diesel fuel oil system component types

that are within the scope of license renewal and subject to an AMR, including closure bolting,

piping, guard pipe, pump casings, strainers (element), strainers (shell), tanks, valve bodies, and

vent screens.

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and FNP FSAR Section 9.5.4. The staff condu6ted its

review using the evaluation methodology described in Section 2.3 of this SER, in-accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

reviewed the FSAR to deterrmine if the applicant had omitted any system functions asan-'

intended function~of the diesel fuel oil system in the LRA, in accordance with the requirements

of 10 CFR 54 4(a). The staff did not identify any omissions. The staff then evaluated, in

accordance with the screening process described in Section 2.3 of this SER, that the applicant

'had identified all passive and long-lived components subject to an AMR, in accordance with 10

CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.14 identified areas in which it needed additional

information to completelthe evaluation of the applicart's scoping and screening' results.'

Therefore, by letter dated March 23,2004, the staff issued several RAls to determine Whether

the applicant had 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 ajplicant's

responses, dated April 22, 2004.

RAI 2.3.3.14-1 - ' '

License renewal boundary drawing D-170060L shows the storage tanks and 'day tanks within

the scope of license renewal. LRA Table 2.3.3.14 lists tanks as a component type subject to an

AMR. However, the details of the storage tanks shown on drawing B-170058L, Sheets 32

I2-89
I

through 36, and the day tanks shown on drawing B-170058L, Sheets 24 through 28, are not

included in the license renewal boundary drawings provided for review. The staff requested'

that the applicant (a) confirm that all internal and external subcomponents of the day tanks and

storage tanks (e.g., manholes and rmianhole covers) are within the scope'of license renewal and

subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR

54.21 (a)(1), respectively, or (b) provide the tank drawings referred to in this RAI for review.

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the subcomponents of the day

tanks and the storage tank, to the extent that they meet the requirements of 10 CFR 54.4(a),

are within the scope of license renewal. The B-drawings referenced in this RAI are equipment

instrumentation drawings and do not detail the internal and external subcomponents of the day

tanks and storage tanks.

With regard to the fuel oil day tanks, the applicant stated that the components shown on

drawing B-170058L, Sheets 24 through 28, are also shown on the license renewal boundary

drawings provided with the LRA. Drawings D-170808L, D-170809L, and D-200213L show all of

the components within the scope of license renewal, with the exception of one in-scope level

switch per tank that is shown on boundary drawing D-1 70060L. These components are within

the scope of license renewal, are passive and long-lived, and are listed in LRA Tables 2.3.3.14

and 3.3.2-14 as being subject to an AMR.

With regard to the fuel oil storage tanks, the applicant stated that Sheets 32 though 36 of

drawing B-170058L show a vent line for the access compartment and a levei transmitter (with

associated tubing) for the storage tank that is not shown on the corresponding license renewal

boundary drawing D-1 70060L. The vent line does not perform a safety-related function and its

failure would not adversely affect a safety-related component or the performance of a safetyrelated function. Therefore, the applicant excluded the vent lines for the access compartments

from the scope of license renewal. The level transmitter with associated tubing provides tank

level and is conservatively included within the scope of license renewal. The level transmitter is

an active component and is not subject to an AMR. Tables 2.3.3.14 and 3.3.2-14 of the LRA

list the associated tubing in the component type 'piping" as being subject to an AMR.

The applicant further stated that license renewal boundary drawing D-1 70060L highlights all the

fuel oil storage tank components of a mechanical nature that are within the scope of license

renewal. The highlighted dashed line on boundary drawing D-170060L around the storage

tanks represents the "manhole shell" that is also shown on drawing B-i 70058L. This is also

called the access compartment for the storage tanks. The manhole, manhole covers, and

access compartment (including the roof of the compartment and the compartment access

doors) are all within the scope of license renewal and are included in LRA Tables 2.3.3.14 and

3.3.2-14 as component types subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-1 acceptable

because it adequately identifies the subcomponents of the day tanks and storage tanks that are

within the scope of license renewal and subject to an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively. Therefore, the staff

considers RAI 2.3.3.14-1 resolved.

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RAI 2.3.3.14-2

License renewal boundary drawings D-170808 and D-200213 show pipe guards from the fuel

day tank vent lines to the diesel bay wall within the scope of license renewal. LRA Table

2.3.3.14 lists pipe guards as component types subject to an AMR. However, pipe guards on

1 1h-in. HBC-224 pipe lines from the valve boxes to the day tank containment bay are not within

the scope of license renewal, as depicted on license renewal boundary drawing D-170060L.

These pipe guards provide shelter protection for the fuel oil transfer lines and are passive and

long-lived components. The staff requested that the applicant justify the exclusion of these pipe

guards from the scope of license renewal and from an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively.

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the pipe guards addressed by this

RAI were installed in the original construction of FNP to protect the diesel fuel lines and are

located in the rear hallway of the diesel generator building. The pipe guards do not perform any

safety-related function, and their failure cannot prevent a safety-related function. These pipe

guards are not required for any of the regulated events defined in 10 CFR 54.4(a)(3) and are

not relied upon in the FNP licensing basis for compliance with 10 CFR 50.48. Therefore, the

applicant concluded that the guard piping does not perform any intended function, in

accordance with the requirements of 10 CFR 54.4(a), and is not subject to an AMR.

Based on its review, the staff finds the response to RAI 2.3.3.14-2 acceptable because it

adequately explains the applicant's basis for excluding the pipe guards from the scope of.

license renewal and from an AMR, in accordance with the requirements of -10 CFR 54.4(a) and

10 CFR 54.21 (a)(1), respectively. Therefore, the staff considers RAI 2.3.3.14-2 resolved.

RAI 2.3.3.14-3

License renewal boundary drawing D-170060L shows that portions of the 3" HBD-443 line, at

locations G3; G5, G8, G10,tand G12, are within the scope of license renewal. However, the

isolation valves (NSY52-V514, V513, V512, V511 and V510 at locations H3, H5, H8, Hi0 and

HI3, respectively) and the portions of the.HBD-443 line downstream of these valves are not

within the scope of license renewal. The isolation valve bodies provide pressure boundary

isolation for the portions of the pipe that are within the scope of license renewal and are passive

and long-lived components. The staff requested that the applicant explain why it excluded.*

these isolation valves from the scope of license renewal and from an AMR, in accordance with

the requirements of 10 CFR 54.4(a) and .10 CFR 54.21 (a)(1), respectively.

Anplicant's Response and Staff's Evaluation ; -

By letter dated April 22, 2004, the applicant responded that the fuel oil storage tanks shown on

license renewal boundary drawing D-170060L are buried tanks with an access compartment

that sits above each tank. The safety-related fuel oil transfer pumps are located inside the

access compartment. The gravity fill line for the storage tanks enters the access compartment

above the pumps and is seismically supported inside the compartment. -The portion of the line

outside the access compartment, up to the flanged connection, is robustly supported. However,

because these lines are gravity fill, the isolation valves do not perform an intended function.

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fl

The applicant stated that the line from the compartment up to the flange connection prevents

moisture intrusion into the tank from the outside and was conservatively included within the

scope of license renewal.

The applicant further stated that for the remainder of the line, including the aforementioned

isolation valves, no failure mode would adversely impact the safety functions of the diesel fuel

oil system or adversely impact the safety-related components. These lines are gravity fill and

the isolation valves do not perform a license renewal intended function, in accordance with 10

CFR 54.4(a). Therefore, the rest of the fill line is not within the scope of license renewal.

Based on its review, the staff finds the response to RAI 2.3.3.14-3 acceptable because it

adequately (1) explains the applicant's basis for excluding the isolation valves and portions of

the HBD-443 line downstream of these valves from the scope of license renewal and from an

AMR, and (2) identifies portions of the 3" HBD-443 line that are within the scope of license

renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10

CFR 54.21 (a)(1), respectively. Therefore, the staff considers RAI 2.3.3.14-3 resolved.

RAI 2.3.3.14-4

License renewal boundary drawings D-170808L, D-170809L, and D-200213L show

instrumentation symbols that are not identified on the standard P&ID legend. The applicant

does not define instrumentations designated as NSR43MA506 and N1 R43MA507 on D170808L; NSR43MA508 and N1R43MA510 on D-170809L; and N2R43MA509 on D-200213L,

in either the LRA or the FSAR. The staff requested that the applicant define these E

instrumentation components and clarify whether they penetrate the fuel oil supply tank pressure

boundary. If so, the staff requested that the applicant explain why it excluded the

instrumentation components from an AMR, in accordance with the requirements of 10 CFR

54.21 (a)(1).

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the instruments addressed by this

RAI are water detectors and are within the scope of license rehewal for the intended function of

pressure boundary, including the tubing (piping in LRA Table 2.3.3.14) to the detectors, as

shown on the license renewal boundary drawings referenced above. Although the tubing

(piping) is passive and requires an AMR, the detector itself is active and therefore does not

require an AMR.

Based on its review, the staff finds the response to RAI 2.3.3.14-4 acceptable because the

applicant identified the instruments addressed in the RAI and justified their exclusion from an

AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1). Therefore, the staff

considers RAI 2.3.3.14-4 resolved.

2.3.3.14.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant omitted any SSCs that should be within the scope of license renewal.

The staff did not find any omissions. In addition, the staff performed an independent

assessment to determine whether the applicant omitted any components that should be subject

2-92
to an AMR. The staff did not identify any ormissions.' On the basis of its review, the staff

concludes'that the applicant has' adequately identified the compon6nts of the diesel fuel oil

system that are within the 'scope of license renewal,;as required by 1 0 CFR -54.4(a), and that

the applicant has adequately identified the conpone'nts of the diesel fuel oil systemrthat are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.15 Emergency Diesel Generator System

2.3.3.15.1 Summary of Technical Informatioi in the Application

In Section 2.3.3.15 of the LRA, the applicant described the emergency diesel generator system

(EDG). For the purposes of liceinse ren6'wal, th6 EDG 'system consists of the FNP EDG system

and the FNP diesel and auxiliaries system, which includes the following EDG support systems:

* EDG lube oil system

* EDG intercooler water system/air coolant system

* EDG jacket cooling system

* EDG'air start system

* EDG air intake and exhaust system'

The EDG system provides alternating current (ac) power to the'onsite electrical distribution

system to assure the'capability for a safe shutdown in the event of a loss of offsite power. The

EDG support systems are necessary to assure proper operation of the EDGs. The EDGsupport systems' provide stored energy for starting the' EDGs, along' with cooling, lubrication,

and combustion air intake and exhaust, to allow the EDGs to perform their function as ; --

described above. The FNP service water system, which is part of the FNP open-cycle cooling

water system, supplies the cooling water to the EDG support systelms heat exchangers. - -

In Table 2.2-1c of the LRA, the applicant'identified the following 10 CFR 54.4(a) criteria it used

to determine the EDG system corriponentswvhich are within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))'

* -station blackout (10 CFR 54.4(a)(3))

In Table 2.3.3.15 of the LRA, the applicant listed theEDG system component types that are

within the scope of license r6newal and subject toari'AMR, including air accumulators, closure

bolting, ducts and fittings, electric heaters, q frames and housings, filters (casing), flow

orifice/element, heat exchanger (channel head), heat exchanger (shell), heat exchanger

(tubesheet, heat exchanger (tubes), piping, pump casings, strainers (elements), strainers

(shell), tanks, arid valve bodies.

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 and FNP FSAR Sections 8.3.1, 9.5.5, 9.5.6, and 9.5.7.

The staff cornducted its review using the evaluationhmethodology described in Section 2.3 of this

SER, in accordance with the guidance described in Section 2.3 of NUREG-1800.'

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1'

In its evaluation, the staff, using the scoping process described in Section 2.3.of this SER,

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function in the EDG system in the LRA, in accordanbe with the requirements of 10

CFR 54.4(a). The staff did not identify any omissions.. The staff then determined, in

accordance with the screening process described in Section 2.3 of this SER, that the applicant

had identified all passive and long-lived components subject to an AMR, in accordance with 10

CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.15 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff issued several RAls to determine whether

the applicant had 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, dated April 22, 2004, and June 10, 2004.

RAI 2.3.3.15-1

License renewal boundary drawings for the EDGs show that the non-safety-related air

dryers/aftercoolers in the air start systems were excluded from the scope of license renewal.

These air dryers/aftercoolers perform the intended function of removing moisture anzd cooldown

air entering the reservoir, thus preventing the EDG starting air system from clogging as a result

of excessive moisture. The safety-related air reservoir tank could not perform its intended

function, should the air dryer/aftercooler fail. The staff requested that the applicant justify the

exclusion of these components from the scope of license renewal and from an AMR, in

accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively.

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that, based on the additional review of

the air dryer/aftercooler assemblies for the diesel generator air start subsystem with respect to

the criteria of 10 CFR 54.4(a), it had determined that these components are within the scope of

the license renewal, but for reasons other than those cited in this RAI.

The applicant stated that the safety-related function of the air start system is to provide air to

support up to five attempts to start the diesel generator associated with each air start train. To

assure this function, the applicant determined that the in-scope, safety-related boundary of the

air start subsystems begins at the inlet isolation check valves for the air receivers in the.

subsystem, includes the receivers, and continues on the outlet side of the receivers all the way

to the diesel generator engine block (the engine block is also within the scope of the license

renewal).

The applicant added that, due to 10 CFR 54.4(a)(2) scoping, the boundary also includes the

attached piping and associated supports on the inlet side of the receivers. The air

dryer/aftercooler assembly is the anchor for the seismic analysis of the safety-related inlet

piping. Therefore, the air dryer/aftercooler assemblies and the intervening piping and

components up to the receiver are within the scope of the license renewal. The applicant

further stated that the component function of serving as an anchor is the only reason the air

dryer/aftercooler assemblies require an AMR.

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The applicant concurred that the air dryer/aft~eb6ooeer assemblies should have been included in

LRA Table 2.3.3.7 as a 'comrponent type'subje'ft to an AMR with the intended function of

structural support. 'The.applicant, in its response, provided tables for the addition of this

component to LRA Table 2.3.3.7 and Table 3.3.2-15.''--'

Based on its review, the staff finds the applicant's response to RAI 2.3.3.15-1 acceptable'

because it adequately explains the basis for including the air dryer/aftercooler assemblies within

the scope of license'renewal, in accordance with the requirements of 10 CFR 54.4(a). The

applicant also concurred that the air dry*r/after'coole'r'assemblies should have been identified in

LRA Table 2.3.3.7 as a component type subject town 'AMR, in accordance with the

requirements of '10 CFR 54.21 (a)(1). Therefore', tle staff considers RAI 2.3.3.15-1 resolved.

RAI 2.3.3.15-2

The staff requested that the applicant clarify how it addressed sight glasses, air distributors,

and vacuum manometers shown on the EDG license renewal boundary drawings in the LRA.

Lice'nse renewal boundary drawings D-l70800L, D-170801L, D-170804L, D-170805L, D-;-.

1 70806L,-D-1 70807L, D-200209L, D-20021 IL, 'and D-20021 2L show these components within

the scope of license renewal. 'However, LRA'Table 2.3.3.7 does not list sight glasses, air.

distributors, and vacuum'- manometers as compon'ent types subject to an AMR.' These

components serve' the intended function of pressure boundary and are passive and long-lived.

The staff requested that the applicant clarify whether' it had the aforementioned components in

LRA Table 2.3.3.7 as part of any component grop. If not, the staff requested that the

applicant justify the exclusion of these components from an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1).

Agplicant's Resionse and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that sight glasses serve the intended

function of pressure boundary in the liquid-bearing subsystems associated with the diesel

generator, are'passive and long-lived comrpofiets, and are therefore subject to an AMR. The

applicant stated that it should have identified'sight glasses in LRA Table'2.3.3.15 as a

component type subject to an AMR,'with the intended function of pressure boundary. The

applicant, in Its response, provided tables for the addition of this component to LRA Tables

2.3.3.15 and 3.3.2-15, accordingly.

The applicant further stated that the a'rdistribitor assemblies-serve the intended function of

pressure boundary, are passive and long-lived components, and are therefore subject to an -

AMR. The applicant models the air distributors as 'valve bodies, the associated tubing as

piping, and the filter casings as filter'casitgs. -

With respect to vacuum mafiometdi, the applic~afit stated that vacuum manometers are an

active indicator and therefore are not listed in LRA Table 2.3.3.15 as a component type subject

to an AMR.

Based on its review, the staff finds tthe app licanrt's response to RAI 2.3.3.15-2 acceptable

because the applicant (1) concurred that sight glasses are subject to an AMR and should have

been'identified in LRA Table 2.3.3.'15,(2)'explain'ed the basis forexcluding the vacuum

manometers from an AMR, in' accordance 'with the requirements of 10 CFR 54.21 (a)(1), and (3)

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R

explained that air distributor, assemblies and the associated tubing and filter casings are within

the scope of license renewal and listed in other component types as being subject to an AMR,

in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively.

Therefore, the staff considers RAI 2.3.3.15-2 resolved.

RAI 2.3.3.15-3 -

License renewal boundary drawing D-506446L for the EDGs shows intake silencers, large and

small mufflers (silencers), and expansion joints within the scope of license renewal. These

components are passive and long-lived, but the applicant did not list them in LRA Table 2.3.3-.

15 as component types subject to an AMR. The staff requested that the applicant justify the

exclusion of these components from an AMR, in accordance with the requirements of 10 CFR

54.21 (a)(1).

Apglicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that it included the intake silencers and

large and small mufflers (silencers) in the component type "equipment frames and housings;"

the expansion joints are included in the component type "ductwork and fittings" in LRA Table

2.3.3.15. The expansion joints are constructed of stainless steel. However, the applicant

omitted the rubber boot installed on the intake side of the diesel generator from the table. This

flexible connector has the intended function of pressure boundary. The applicant included

information on the rubber boot in its response to RAI 2.2-5a.

After reviewing the applicant's response, the staff concluded that the response differs from the

information in LRA Table 3.3.2-15. In its response, the applicant stated that the equipment

frames and housings component type is used to model the intake silencers and mufflers in LRA

Table 2.3.3.15. However, LRA Table 3.3.2-15 lists the intake silencers under 'ducts and

fittings."

During a telephone conference on May 24, 2004, between the applicant and the NRC staff, the

applicant agreed to revise its April 22, 2004, response to RAI 2.3.3.15-3. By letter dated

June 10, 2004, the applicant, in its revised response, stated that intake silencers, mufflers, and

expansion joints are included under the component type "ducts and fittings" in LRA

Table 2.3.3.15.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.15-3 acceptable

because it (1) clarifies that the intake silencers, large and small mufflers, and expansion joints

are included in the component type "ductwork and fittings" in LRA Table 2.3.3.15 and are

subject to an AMR, in accordance with the requirements 10 CFR 54.21 (a)(1), and (2) states

that flexible connectors (rubber boots) will be included in LRA Tables 2.3.3.15 and 3.3.3.15 as

component types subject to an AMR. Therefore, the staff considers RAI 2.3.3.15-3 resolved.

RAI 2.3.3.15-4

The staff requested that the applicant clarify whether it scoped and screened the components

of the EDGs in the LRA as complex assemblies. Regarding complex assemblies, Table 2.1-2

of NUREG-1 800 states that "some structures and components, when combined, are considered

a complex assembly.... An applicant should establish the boundaries for each assembly by

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identifying each structure and component that rriakes dp the compl6i assembly and

determining whether or not each structure a'nd cornponerit is subjeci to an AMR." The staff

requested that the applicant identify the boundaries of the EDGs to determine whether the

subcomponents (turbochargers, turbocharger aftercoolers, governors, etc.) are within the scope

of license renewal and subject to an AMR, in accordance with the requirements of 10 CFR

54.4(a) and 10 CFR 54.21(a)(1), respectively.

Applicant's Resoonse and Staff's EvaluationBy letter dated April 22, 2004, the applicant irsponded that SNC had considered the

requirements of 10 CFR 54.21 (a)(1), the guidance provided in Table 2.1-2 of NUREG-1800,

and the Statements of Consideration (SOCs) for the Rule in determ ining th6 boundary between

the active diesel generator and the EDG support systems. The engine block and its integral

attachments are the starting point for defining the active diesel generator component: The'

turbochargers, exhaust manifold (though not the exhaust ducts), turbocharger aftercoolers, and

governors are included as'part of the active diesel generator component with their performance

validated under the Mainten'ance Rule because of the frequent testing of the EDGs and the

periodic maintenance and overhaul activities -' '

In response to the staff's request of whether the'subcomponents addressed in the RAI are

subject to an AMR, the applicant responded that passive parts of SCs that only perform an

active function are not subject to an AMR according to' 10 CFR 54.21 (a)(1) and the SOCs for

the Rule (60 FR 22472). The SOCs and'the 'Rule cite the diesel generators as an example of a

component that is'fully active and can be excluded from an AMR. The applicant manages agerelated degradation of the active diesel generat r in accordanc'e with the requirements of the

Maintenance Rule.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.15-4 acceptable

because it adequately identifies the boundaries of the EDG system and explains the basis for

excluding the subcomponents of the EDG system fro'man AMR, in accordance with the

requirements of 10 CFR 54.21(a)(1), the guidance ,provided in Table 2.1-2 of NUREG-1 800,

and the SOCs for the Rule. Therefore, the staff considers RAI 2.3.3.15-4 resolved.

RAI 2.3.3.15-5

FNP FSAR Section 9.5.7.2.1 states, "The built-in lubricating oil sump is driven from the engine

drive gear and draws oil from the oil sump through a mesh screen intake screen." Similarly,

FNP FSAR Section 9.5.7.2.2 states, "The built-in lubricating oil pump is driven by the engine

through a flexible drive coupling and draws oil from the oil sump through a mesh intake screen."

The mesh intake screens are not show'n 'on the license renewal boundary drawings for the EDG

system; The mesh intake screens are passive and long-lived components, but are not listed in

LRA Tables 2.3.3.15 and 3.3.2-15 as component types subject to an 'AMR. The mesh screens

provide the intended function of idebris protection for the pipelines. The staff requested that the

applicant identify the mesh intake screens on the license renewal boundary drawing and justify

the exclusion of these components from the scope-of license renewal and from an AMR, in

accordance with the requirements of 10 CFR 54.4 (a) and 10 CFR 54.21 (a)(1), respectively.

Applicant's Response and Staff's Evaluatioan-?i.

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By letter dated April 22, 2004, the applicant responded that the intake mesh screens are within

the scope of license renewal and are shown indirectly on the license renewal boundary drawing

in the suction strainer. The applicant further stated that these mesh screens are included in

LRA Tables 2.3.3.15-1 and 3.3.2-15 in the component type "strainers (element)," with an

intended function of debris protection in a lube oil environment.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.15-5 acceptable

because it identifies the location of the mesh intake screens on the license renewal boundary

drawing and clarifies that the mesh intake screens are within the scope of license renewal and

listed in the component type "strainers (element)" as being subject to an AMR, in accordance

with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively. Therefore, the

staff considers RAI 2.3.3.15-5 resolved.

RAI 2.3.3.15-6

(a) The first paragraph of FNP FSAR Section 9.5.7.3, which describes the internal oil

system for the diesel engines 1 C and 2C, states, "Oil flows through the lower header

toward the blower end where a vertical header will not readily drain." The license

renewal boundary drawings for the EDG system does not show thel C/2C EDG internal

blower. Although a blower is an active, component, the blower housing could be a

passive long-lived component. However, the applicant did not list the blower housing in

LRA Table 2.3.3.15 as a component type subject to an AMR. The staff requested that

the applicant explain how the LRA addresses the blower housing and, if required, justify

its exclusion from the scope of license renewal and from an AMR, in accordance with

the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively.

(b) The second paragraph of FNP FSAR Section 9.5.7.3 states, uThe cooling oil from each

lower piston is discharged through a hole in the insert.... This oil then drains either

toward the blower or the control end and down to the oil pan or subbase." The license

renewal boundary drawings do not show the 1 C/2C EDG oil pan and it is not listed in

LRA Table 2.3.3.15 as a component type subject to an AMR. The intended function of

the oil pan/subbase is not specifically stated; typically, the oil collection pan's intended

function is to ensure that leaking oil will not lead to a fire that could damage safetyrelated equipment. The staff requested that the applicant justify the exclusion of this

component from the scope of license renewal and from an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively.

Applicant's Response and Staff's Evaluation

(a) By letter dated April 22, 2004, the applicant responded that the blower referred to in

FSAR Section 9.5.7.3 is a positive displacement-type blower that provides scavenging

air under pressure to the cylinders for starting and light load operation. The blower is

integrally attached to the engine block and only required to function during diesel

generator operation. Therefore, the applicant included the blower as an integral part of

the diesel generator active component.

In response to the staff's request of whether the blower housing is subject to an AMR,

the applicant stated that passive parts of SCs that only perform an active function do not

require an AMR, according to 10 CFR 54.21 (a)(1) and the SOCs for the Rule (60 FR

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22472). The SOCs, as well as the Rule cite'the- diesel generators as an example of a

component that is fully active and can be'excluded from-an AMR. The diesel generator

(including the blower) performs only an active function; theref ore, its passive parts do

not require an AMR. The applicant manages age-related degradation of the active

diesel generator (including the blower housirig)'in accordance with the requirements of

the Maintenance Rule.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.1 5-6a

acceptable because it adequately explains'the basis for excluding the blower housing

from the scope of license renewal and frorn an AMR, in accordance with the

requirernents of 10 CFR '54.4(a), 10 CFR 54.21 (a)(1), and the SOCs for the Rule.

Therefore, the staff considers RAI 2.3.3.15-6a resolved. -

(b) By letter dated April '22, 2004, the applicant'responded that the'oil pan referred to in

FSAR Section 9.5.7.3 is not a pan for collecting "leaking oil," but rather the typical oil

sump provided for an engine by a panir hiourited -oh the bottom of the block.- In screening

the diesel 'generators, the applicant treated the oil pan'as an integral part of the'engine

components. The oil pan s integrally attached to the engine blockand dnly required to

functioh during the diesel generator operatidn. "Therefore, the applicant included the oil

pan as an integral part of the diesel generator active component.

In response to the staff's request as to whether the oil pan is subject to an AMR, the

applicant responded that passive parts of SCs that only perform an active function are

not subject to an AMR,' according tol- O'CFR 54.21 (a)(1) and the SOCs for the Rule.

''The 5005, as well as the Rule, cite the 'diesel generators as a6n'ex6rrple of a

component that'is fully active and can be excluded from an AMR.' The diesel generator

(including the oi pa'n) performs only'n~active function; thereforea its passive parts are

not subject to an AMR. The applicant miana-ges age-related degradation of the active

diesel generator (including the oil pan) in accordance with the requirements of the

Maintenance Rule.' ''

Based on its review, the staff finds the'applicant's response to RAI 2.3.3.15-6b

acceptable because it adequately 6xpl'ins'the basis for excluding the oil pan frbm the

scope'of license'renewal and from an AMRin accordance with'the requirements of 10

CFR 54.4(a) and 10 CFR 54.21 (a)(1), as well as the SOCs for the Rule. Therefore, the

staff considers RAI 2.3.3.15-6b resolved.

RAI 2.3.3.15-7 .'' ' ( .

(a) License renewal boundary drawing' D-170806L for the EDG system 'shows that lube oil

'engine-driveri pumps of the EDGs 1-2A'ahd '-1 B,'and their associated piping to the

shuttle valve V810, are excluded from the s6ope of license renewal.- 'However,--license

renewal bou'ndary drawing D-200212L shows that the lube oil engine-driven pumps of

the EDG 2B and its associated piping are within the'scope of the'license renewal. The

staff requested that the applicant describe how the aforementioned components for the

EDGs 1-2A and '1 B differ from th'e onmponents for EDG 2B. In addition, the staff

requested that the applicant exp!ain how these'differences were considered in the

scoping and screening process for EDGs'1 -2A and 1 B.

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(b) Ucense renewal boundary drawing D-1 70803L for the EDG system shows air coolers for

the EDGs 1 C and 2C within the scope of license renewal. Air coolers are passive and

long-lived components and are not listed in LRA Table 2.3.3.15 as component types

subject to an AMR. The staff requested that the applicant justify the exclusion' of the air

coolers from an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

Applicant's Response and Staff's Evaluation

(a) By letter dated April 22, 2004, the applicant responded that the lube oil engine-driven

pumps for the 1 -2A and 1 B EDGs, and their associated piping to the shuttle valve V81 0,

are within the scope of license renewal and should have been highlighted on the license

renewal boundary drawing D-1 70806L.

In response to the staff's request of how the aforementioned components for EDGs 1-

2A and 1 B differ from the components for EDG 2B, the applicant stated that there was

an error in the highlighting on the license renewal boundary drawings. The enginedriven lube oil pump shown on license renewal boundary drawing D-1 70806L, Sheet 1,

is QSR43P0526,which is highlighted on license renewal boundary drawing D-170801 L,

Sheet 1. Similarly, the same pump shown on license renewal boundary drawing D170806L, Sheet 2, is QSR43P0505, which is highlighted on license renewal boundary drawing D-1 70801 L, Sheet 2.

Based on its review the.staff finds the applicant's response to RAI 2.3.3.15-7a

acceptable because it adequately identifies the drawings that address the differences

between EDGs 1-2 A and 1 B and EDG 2B and clarifies that the lube oil engine-driven

pumps for the 1 -2A and 1 B EDGs, and their associated piping to the shuttle valve V81 0,

are within the scope of license renewal, in accordance with the requirements of 10 CFR

54.4(a). Therefore, the staff considers RAI 2.3.3.15-7a resolved.

(b) By letter dated April 22, 2004, the applicant responded that the air coolers were treated

as an integral part of the engine components. The air coolers are bolted onto the

engine block and are only required to function during the diesel generator operation.

The engine block and its integral components are part of the active part of the engine.

Therefore, the applicant included the air coolers as an integral part of the diesel

generator active component.

The applicant further stated that passive parts of SCs that only perform an active

function are not subject to an AMR, in accordance with 10 CFR 54.21 (a)(1) and the

SOCs for the Rule. The SOCs for the Rule cite the diesel generators as an example of

a component that is fully active and can be excluded from an AMR. The diesel

generator (including the air cooler) performs only an active function; therefore, its

passive parts are not subject to an AMR. The applicant manages age-related

degradation of the active diesel generator (including the air cooler) in accordance with

the requirements of the Maintenance Rule.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.15-7b

acceptable because it adequately explains the basis for excluding the air coolers from

an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1) and the SOCs for

the Rule. Therefore, the staff considers RAI 2.3.3.15-7b resolved.

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2.3.3.15.3 Conclusion ~ no-"

The staff reviewed the LRA and the'accompanying'scoping boundary drawings to determine

whether the applicant had omitted any SSCi that' should be within the scope of license renewal.

The staff did not identify any omissions. In addition, the staff performed an independent

assessment to determine whether the applicant had identified all components that should be.,:

subject to an AMR. The staff found no omissions. On the basis of its review, the staff

concludes' that the applicant has adequately identified the components of the EDG system that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

has adequately identified the components 6f the EDG -system that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.16 Demineralized Water System

2.3.3.16.1 -Summary of Technical Information in the Application

In Section 2.3.3.16 of the LRA, the applicant described the demineralized water system. The

demineralized water system consists of the demineralized water portion of the condensate and

demineralized water system. The demineralized water system provides demineralized water for

Units 1 and 2 during all'phases'of plant operations. :This includes water for filling, flushing, and

making up losses duririn'startup, shutdown, refueling, power, and maintenance operations.

Demineralized water makeup/supply is not required for performance of any safety-related

function.' Portions of the demineralized water system are brought into scope for containmentisolation (where the demineralized water supply piping penetrates containment) and under the

requirements of 10 CFR 54.4(a)(2) because of spatial interaction and attached piping.

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine demineralized water system components which are within the scope of license

renewal:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

In Table 2.3.3.16 of the LRA, the applicant listed the demineralized makeup water system

component types that are within the scope of license renewal and subject to an AMR, including

closure bolting, filters (casing), piping, and valve bodies.

In its response to RAI 2.1-1 (discussed in Section 2.1 of this SER), the-applicant changed the

methodology used for scoping of non-attached, non-safety-related piping for the demineralized

water system, in accordance with 10 CFR 54.4(a)(2). By letter dated June 4, 2004, the*

applicantsubmitted the supplemental information-associated with the determination of SSCswithin the scope of license renewal, in accordance with'the requirements of 10 CFR 54.4(a)(2),

as a result of the revised scoping methodology (see Enclosure 2, "Joseph M. Farley Nuclear

Plant Units 1 and 2, Application for License Renewal,- Supplemental Information Related to 10

CFR 54.4 (a)(2)").

The inethodology change expanded the'mechanical SSCs within the scope of license renewal.

In its supplemental information'related to 10 CFR 54.4(a)(2), the applicant listed the impact of

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the changes in the 10 CFR 54.4(a)(2) scoping methodology on the LRA results of the in-scope

components for the demineralized water system. Although this table shows an increase in the

in-scope SSCs for the demineralized water system, the applicant stated that the component

types do not differ from those listed in LRA Table 2.3.3.16.

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 and FNP FSAR Section 9.2.3. The staff conducted its

review using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function of the demineralized water system in the LRA, in accordance with the

requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff then

determined, in accordance with the screening process described in Section 2.3 of this SER, that

the applicant had identified all passive and long-lived components subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.16 identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated April 1, 2004, the staff issued an RAI to determine whether the

applicant had 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 RAI and the applicant's response,

dated April 29, 2004.

RAI 2.3.3.16-1

Tables 2.3.3.16 and 3.3.2-16 of the LRA list filter casings as component types subject to an

AMR. However, the license renewal boundary drawings D-1 75047L and D-205047L for the

demineralized water system do not show any filter casings within the scope of license renewal.

The staff requested that the applicant provide drawings or descriptive information that identify

the filter casings in the demineralized water system that are within the scope of license renewal

and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR

54.21 (a)(1), respectively.

Applicant's Response and Staff's Evaluation

By letter dated April 29, 2004, the applicant responded that the filter casings addressed in

RAI 2.3.3.16-1 are located in the auxiliary building. The filter casings are within the scope of

license renewal under 10 CFR 54.4(a)(2) solely because of potential spatial interactions with

safety-related components, the failure of which could prevent satisfactory accomplishment of a

safety-related component intended function. The filter casings are not highlighted on the

license renewal boundary drawings because, for each applicable LRA system, license renewal

boundary drawing D-506447L identifies the room(s) where the potential spatial interaction

occurs.

The applicant further identified the filters N1 P11 F001 and N1 P11 F003 which are shown on the

license renewal boundary drawing D-175047L and located in auxiliary building rooms 186 and

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342, as having a spatial interaction with safety-related SSCs in these rooms.

As part of their review of the implementation of the applicant's scoping and screening

methodology,-as described in the LRA Section 2.1, the NRC inspectors performed a license

renewal scoping and screening inspection that was completed on May 14, 2004, and is

documented in Inspection Report Nos. 50-348/2004-007 and 50-364/2004-007, dated June 22,

2004:The inspection consisted of a selected examination of procedures and representative

records, as well as interviews with personnel, regarding the process of scoping and screening

plant components to select component subject to an AMR. Additionally, the NRC inspectors

performed a walkdown of selected areas of the plant containing SSCs that are considered to be

within the scope of license renewal because they meet the 10 CFR 54.4(a)(2) requirement. For

a sample of plant systems, specifically those that were identified by the NRC reviewers, the

NRC inspectors performed visual inspections of accessible portions of the systems to observe

any effects of component aging. - -

After reviewing the applicant's response, the staff concluded that sufficient information was not

available to resolve its concerns expressed in RAI 2.3.3.16-1. Therefore, the NRC inspectors

performed an inspection during the license renewal scoping and screening inspection, asr

documented in NRC Inspection Report Nos. -50-348/2004-007 and 50-364/2004-007, dated

June 22,2004, for the demineralized water system to evaluate an apparent inconsistency in the

applicant's determination of the system filter components included within the scope of license

renewal as compared to the filter components excluded from the scope of license renewal. As

documented in the NRC Inspection Report Nos. 50-348/2004-007 and 50-364/2004-007, dated

June 22, 2004, the inspectors reviewed the applicant's response, verified the filters referenced

in the RAI, and determined that the applicant had included filters N1 P11 FOO1, N1 P11 F003, and

Ni P11 F004 in accordance with the 10 CFR 54.4(a)(2) spatial criterion. However, filter

N1 P11 F005 was not included in scope because it is in a line to an abandoned component and.

is therefore a dry line. The applicant identified components meeting the 10 CFR 54.4(a)(2)

criterion by identifying them in drawing D-506447L, but not highlighting them on the boundary

drawing for in-scope components. The inspectors concluded that the applicant had

appropriately identified these filter components for the demineralized water system.

The staff found an inconsistency between the filters (Ni P11 FO01 -and Nl P11 F003) identified by

the applicant in its response as being within the scope of license renewal and those filters

(N1 P11 F001, N1 P11 F003, and Ni P11 F004) that were identified in the inspection report.

Therefore, the staff requested that the applicant revise its RAI response to resolve this

inconsistency.

By letter dated July 27,2004, the applicant responded that its response to RAI 2.3.3.16-1,

dated April 29, 2004, was provided prior to implementation of its revised 10 CFR 54.4(a)(2)

scoping methodology. The applicant's revised methodology replaced the 20 foot spatial

separation criterion with the spaces approach. In implementing the revised methodology, the

applicant reevaluated the location of each of the demineralized water filters to determine if a

spatial interaction with vulnerable safety-related SSCs was possible.

As a result, the applicant identified filter N1 P11 F001 in Room 342, in the same room as the

spentfuel pool cooling pumps; filter N1P11FO03 in Room 186, in the same room as the boric

acid transfer pumps; and filter N1 P11 F004 in Room 180/186, located in the same space as

vulnerable safety-related SSCs but separated from it by a wall, as within the scope of license

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'I

renewal. The applicant identified filter N1 P11 F005, which is normally dry and not in a room with

a vulnerable safety-related SSCs, as excluded from the scope of license renewal. This is

consistent with the findings of the NRC inspection report. Subsequent to the initial RAI

response and the inspection, the applicant determined that filter Ni P11 F006 in Room 185,

which is in the same room as the component cooling water pumps, is also within the scope of

license renewal even though the filter is very far away from the pumps. In its revised response

to RAI 2.3.3.16-1, dated July 27, 2004, the applicant provided a table that illustrates the scoping

of the filters that are shown on the license renewal boundary drawing D-1 75047L, Sheet 1.

Because rooms 177/178 do not contain any safety-related SSCs, filter N1 P11 F008 in Room

177/178 is listed in this table as "Not In Scope."

Based on its review, the staff finds the applicant's revised response to RAI 2.3.3.16-1

acceptable. The staff finds that the applicant adequately identified the filters that are within the

scope of license renewal because of spatial interaction of a non-safety-related component, the

failure of which may prevent a safety-related component from performing its intended function,

with safety-related equipment. Therefore, the staff considers RAI 2.3.3.16-1 resolved.

The staff finds the supplemental information related to 10 CFR 54.4(a)(2) in the June 4, 2004,

Enclosure 2 (discussed in Section 2.2.3) to be acceptable, on the basis that it adequately

identified all DW system's non-safety-related SSCs that are added to the scope of license

renewal as a result of the changed 10 CFR 54.4(a)(2) scoping methodology.

2.3.3.16.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant had omitted any SSCs that should be within the scope of license renewal.

The staff did not identify any omissions. In addition, the staff performed an independent

assessment to determine whether the applicant had identified all components that should be

subject to an AMR. The staff found no omissions. On the basis of its review, the staff

concludes that the applicant has adequately identified the components of the demineralized

water system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant has adequately identified the components of the demineralized water system

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

2.3.3.17 High-Energy Line Break Detection System

2.3.3.17.1 Summary of Technical Information in the Application

In Section 2.3.3.17 of the LRA, the applicant described the high-energy line break (HELB)

detection system. For the purposes of license renewal, the HELB detection system includes

compartment/room pressure and level sensors assigned to the following systems:

* boron thermal regeneration system

* liquid waste disposal system

* steam generator blowdown system

* auxiliary steaam system

* condensate and feedwater system

* penetration room filtration system

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The HELB detection system monitors compartment/room pressures or levels to detect HELBs.-

The sensors alarm in the control room to alert plant operators and, in most cases, automatically

isolate the associated high-energy line(s). --

Room pressure'sensors monitor areas affected by a CVCS letdown line or boron thermal

regeneration system (BTRS) high-energy line rupture and automatically isolate the CVCS

letdown line if an HELB is detected. These sensors are assigned to the BTRS and liquid waste

disposal system. Room pressure sensors assigned to the steam generator blowdown (SGBD)

system monitor areas affected by an SGBD line rupture and automatically isolate the SGBD line

if an HELB is detected. Room pressure sensors assigned to the auxiliary steam system -

monitor areas affected by a rupture of an auxiliary steam supply line to the turbine-driven AFW

pump and'alarm in the control room (no isolation feature) if an HELB is detected. Pressure

sensors assigned to the penetration room filtration (PRF) system monitor the penetration room

to detect elevated room pressure and alarm in the control room.

Level sensors assigned to the condensate and feedwater system are provided in the main

steam valve room to detect flooding indicative'of a line rupture. The level sensors trip the main

feedwater pumps if the setpoint is exceeded. Tripping of the main feedwater pumps causes the

feedwater isolation valves to close.

The HELB detection system bnly includes the compartment/room pressure and level sensors.

The components utilized to isolate specific lines are addressed as part of the associated

system.

In Table 2.2-1c 6f the' LRA,-the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the HELB detection system components which are within the scope of license -

renewal:

* 'safety-related (10 CFR 54.4(a)(1))

* fire protection (10 CFR 54.4(a)(3))

* ' - environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.17 of the LRA, the applicant listed the HELB detection system component types

that are within the scope of license renewal and subject to an AMR, including piping and valve

bodies.

2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.17 and FNP FSAR Appendix 3K. The staff conducted its

review using the' evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800. . ;

In its evaluation, the staff, using the scoping process described in Section 2.3 of this SER,

reviewed the FSAR to determine if the applicant had omitted any system functions as an

intended function of the HELB system in the LRA, in accordance with the requirements of

10 CFR 54.4(a). The staff did not identify any omissions. The staff then determined, in

accordance with the screening process described in Section 2.3 of this SER, that the applicant

had identified all passive and long-lived components subject to an AMR, in accordance with

10 CFR 54.21 (a)(1).

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I I

The staff's review of LRA Section 2.3.3.17 identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff issued an RAI to determine whether the

applicant had 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 RAI and the applicant's response,

dated April 22, 2004.

RAI 2.3.3.17-1

The applicant lists piping and valve bodies as component types subject to an AMR in LRA

Table 2.3.3.17. However, the license renewal boundary drawings which show the HELB

detection instruments do not show the piping or valves associated with these instruments.

Appendix 3K to the FNP FSAR does not describe the piping and valves associated with the

HELB pressure and level sensors. The staff requested that the applicant provide descriptive

information or drawings to allow the staff to confirm that the components in the HELB system

are within the scope of license renewal and subject to an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively.

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the HELB detection instruments are

pressure switches that are installed with an isolation valve and piping/tubing routed to the room

being sensed. The piping/tubing is 3/8" A-123 Gr. 304 stainless steel, and the fittings are:

forged stainless steel compression fittings per ASTM A-1 82, Gr. 316. The valves are 3/8N

globe-type instrument valves with forged stainless steel bodies of ASTM A-479, Gr. 316. The

internal and external surface of these components are exposed to the inside environment of the

auxiliary building.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-1 acceptable

because it identifies the piping and valve bodies associated with the HELB detection

instruments and clarifies that the HELB system components are within the scope of license

renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1), respectively. Therefore, the staff considers RAI 2.3.3.17-1 resolved.

2.3.3.17.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant had omitted any SSCs that should be within the scope of license renewal.

The staff did not find any omissions. In addition, the staff performed an independent

assessment to determine whether the applicant had identified all components that should be

subject to an AMR. The staff did not identify any omissions. On the basis of its review, the

staff concludes that the applicant has adequately identified the components of the HELB

detection system that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and that the applicant has adequately identified the components of the HELB detection system

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

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2.3.3.18 Hydrogen Control System

2.3.3.18.1 Surmnrary of Technical Inforrmation in the Application

In Section 2.3.3.18 of the LRA, the applica'rit described the components of the hydrogen control

system, which includes the following FNP systems: -

* containment hydrogen recombiner system -

* containment post-LOCA air mixing system;

* reactor cavity hydrogen dilution systerm '

* postaccident containment venting and sampling system

The containment hydrogen recombiner system consists of redundant electrical recombiners,,

which are' located inside the containment, for controlling hydrogen concentrations in the

containment atmosphere following a designr-basis accident. The recombiners' controls are._

located outside the containment. The recombiner units are situated in the containment such

that they process a flow of containment air containing hydrogen at a concentration that is typical

of the average concentration throughout the containment during accident conditions.- .

. ' 1 .: .- , , , . x,

The containment post-LOCA air mixing system c6n'sists of four-fans in two redundant trains that

provide mixing of the containment atmosphere to prevent localized accumulation of hydrogen

gas to concentrations greater than the lower flammability limit. - --

The reactor cavity hydrogen dilution system-consists of two redundant fans that provide mixing

of the containment'atmosphere within the reactor cavity to prevent localized accumulation of

hydrogen gas to concentrations greater than the'lower flammability limit.

The postaccident containment venting and sampling system provides the ability to vent the

containment atmosphere as a-backup to the hydrogen recombiner system. The sampling

portion of this system provides for monitoring of the containment atmosphere. Since the

venting of the containment atmosphere is used only as a backup to the hydrogen recombiner

system, it is not required to mitigate the consequences of an accident. However, if it is used,

the filtration function supports maintaining offsite exposure comparable to the guidelines of

10 CFR 100.11 and, therefore, is included in the scope of license renewal.

In Table 2.2-1c of the'LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the hydrogen control system'SSCs that are within the scope of license renewal: .... ..iI - .; .- -.' ......

* 'safety-related (10 CFR 54.4(a)(1)) A .-

* ienvironmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.18 of the LRA, the applicant listed the hydrogen control system component types

that are within the scope of license renewal and subject to an AMR, including the closure

bolting, equipment frames and housings, filters (casing), flow orifice/element (annubar),

hydrogen recombiner, piping, sample analyzers (pressure-retaining components), and valve

bodies. ' '' , '

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2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 and FNP FSAR Section 6.2.5 to determine whether

the applicant identified the hydrogen control system components within the scope of license

renewal and subject to ari AMR, in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The

staff conducted its review in accordance with Section 2.3 of NUREG-1800.

In its evaluation, the staff reviewed the FSAR to determine if the applicant identified in the LRA

all safety-related system functions as an intended function of the hydrogen control system, in

accordance with the requirements of 10 CFR 54.4. The staff did not identify any omissions.

The staff also selected system functions described in the FSAR and required by 10 CFR 54.4 to

verify that the applicant had not omitted components having intended functions from the scope

of the Rule. The staff also focused on those components that the applicant had not identified

as subject to an AMR to determine if any components were improperly omitted.

To verify that the applicant identified the components of the hydrogen control system 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 boundary drawings to the system

drawings and system descriptions in the FSAR to ensure that the referenced boundary

drawings were representative of the hydrogen control system. -The staff then reviewed the

referenced boundary drawings to verify that the applicant had included those portions of the

hydrogen control system that meet the scoping requirements of 10 CFR 54.4 within the scope

of license renewal, and that it had identified them as such in LRA Section 2.3.3.18; and the

applicant identified all hydrogen control 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's review of LRA Section 2.3.3.18 did not identify areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, the staff did not issue any RAIs to determine whether the applicant had properly

applied the scoping criteria of 10 CFR 54.4 and the screening criteria of 10 CFR 54.21.

2.3.3.18.3 Conclusion

During its review of 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

hydrogen control system components. The staff concludes that the applicant has adequately

identified the hydrogen control 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 hydrogen

control system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.19 Liquid Waste and Drains

2.3.3.19.1 Summary of Technical Information in the Application

In Section 2.3.3.19 of the LRA, the applicant described the liquid waste and drains (LW&Ds).

The LW&Ds system collects, segregates, and processes reactor-grade and nonreactor-grade

liquid wastes produced during plant operation, refueling, and maintenance activities. This

system also includes the equipment and floor drainage system. Reactor-grade liquid waste

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may be recycled for plant use or processed for disposal. Nonreactor-grade liquid wastes are

processed for disposal. -The system is designed to control and minimize releases of

radioactivity to the environment. Measurements of the rates at which various liquid waste

streams accumulate and the frequency of sump pump operation are used as indicators of

possible system leakage. -

The containment cooler condensate level monitoring subsystem is part of the LW&Ds system

and is conservatively included in the scope of license renewal. This subsystem is credited as a

means to detect reactor coolant pressure boundary leakage in the CLB, including as part of the

leak before break (LBB) analyses. The containment cooler condensate level monitoring

subsystem collects the liquid runoff from the drain pans under each containment cooler fan unit

and will alarm in response to increased condensate flow indicating a potential leak in

containment.-

The portion of the LW&Ds related to the RCP oil collection system is within the scope of license

renewal for FP. This system is designed to collect and contain oil leakage from the RCPs to

minimize the possibility of oil leakage as a fire hazard within the containment building.

For the purposes of license renewal, the portions of the LW&Ds system that penetrate the

containment boundary are brought into scope for containment isolation. Portions of the system

are also brought into scope to meet the requirements of 10 CFR 54.4(a)(2) due to spatial

interaction and attached piping considerations and for isolation of drainpaths to support.

penetration room filtration (PRF) system pressure boundary requirements.

The compartment/room pressure sensors assigned to the LW&Ds system that isolate the

CVCS letdown line in the event of a CVCS letdown line rupture are addressed separately as

part of the HELB detection LRA system boundary.

In Table 2.2-1c of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria used to

determine the LW&Ds system components that are within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3)); -

* -environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.19 of the LRA, the applicant listed the LW&Ds system component types that are

within the scope of license renewal and subject to an AMR, including flexible connectors, piping,

tanks, valve bodies, closure bolting, and floor drain plugs.

In its response to:RAI 2.1-1 (discussed in Section 2.1 of this SER), the applicant changed the

methodology used for scoping unattached, non-safety-related piping for the LW&Ds system in

accordance with 10 CFR 54.4(a)(2). By letter dated June 4, 2004, the applicant submitted the

supplemental information associated with the determination of SSCs within the scope of license

renewal, in accordance with the requirements of 10 CFR 54.4(a)(2) as a result of the changed

scoping methodology (see Enclosure 2, "Joseph M. Farley Nuclear Plant Units 1 and 2,

Application for License Renewal,-Supplemental Information Related to 10 CFR 54.4(a)(2)").

The methodology change resulted in an expansion of the mechanical SSCs within the scope of

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license renewal. In its supplemental information related to 10 CFR 54.4(a)(2), the applicant

listed the impact of changes in the 10 CFR 54.4(a)(2) scoping methodology on the LRA results

of the in-scope components for the LW&Ds system. Floor drains, drain holdup tanks, and

sump pumps that are relied upon in the revised methodology were brought within the scope of

license renewal. The applicant also added the roof drains and sanitary drains systems to the

scope of license renewal and incorporated them into the LW&Ds system. Only those roof

drains that are routed over safety-related SSCs and can adversely impact the performance of

any safety-related SSC were brought into scope because of 10 CFR 54.4(a)(2).

The applicant stated that because of the change in scoping methodology, the leakage detection

functions of the waste holdup tank (WHT) and the floor drain tank (FDT) are considered within

the scope of 10 CFR 54.4(a)(2) and evaluated for aging effects that require management.

Although LRA Table 2.3.3.19 lists the component type "tank," the LW&Ds system AMR

summary does not include stainless steel tanks. As a result, these stainless steel tanks should

be added to LRA Table 3.3.2-19.

The applicant further stated that the floor drains include a cast iron drain body that is embedded

in the concrete floor. Where the drainlines are embedded in the concrete, the material is either

stainless steel or cast iron. Where the drains pass through the space of a room, the piping is

either stainless steel or carbon steel, depending upon the area being drained. Table 2.3.3.19 of

the LRA includes the component type "piping." Table 3.3.2-19 of the LRA already includes the

aging management information for carbon steel components of this type. Cast iron

components in accessible environments are not subject to general corrosion unless they are

installed in a location that is subject to repeated wet-dry cycling. Cast iron that is not subject to

wet-dry cycling develops an adherent oxide layer that limits the effects of general corrosion.

For this reason, the floor drain cast iron components do not have an aging effect that requires

management. The stainless steel embedded components also do not have an aging effect that

requires management in these environments.

The applicant stated that the sump pump casings are stainless steel. The 'pump casing"

component type should be added to LRA Table 2.3.3.19. The stainless steel sump pump

casing and the discharge piping should be added to LRA Table 3.3.2-19.

The applicant stated that the sink and floor drains from the nuclear laundry and the

radiochemistry laboratories are frequently used and are routed in such a way as to pass

through spaces that contain safety-related SSCs. The drains are constructed of stainless steel

material and are most often empty. The water chemistry of the samples that are disposed of in

these drains is at least designated as treated water and often as primary water in purity. As a

result, aggressive chemical species are not likely to build up in the drains through wet-dry

cycling. Therefore, SNC does not expect the drains to experience adverse aging effects during

the period of extended operation. Since the postulated failure modes for this piping are

hypothetical, not evaluated in the FNP CLB, and not experienced at either FNP or in the

industry, this piping is not in the scope of renewal for 10 CFR 54.4(a)(2). This same argument

applies to the other, infrequently used (normally empty) stainless steel floor drains, the effluent

of which is processed through the WHT and the FDT.

On the nonradiologically controlled side of the auxiliary building, portions of the drains are

constructed of carbon steel material. Portions of these carbon steel drains are used to remove

the condensation from ventilation units, and these drains may frequently contain untreated

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water. Since these drains pass bver-safety related SSCs that wv6uld be vulnerable to leakage,

the applicant considered the dfains to be within'the'scope of'10 CFR54.4(a)(2).

The applicant stated that the sanitary drairis 'ar6 f6rmally empty but are often used. They are

normally at atmospheric conditions. The drains are routed in the same areas as safety-related

SSCs, and some are routed over safety-related SSCs. Therefore, leakage from these drainscan cause an adverse impact upon the performance of safety-related SSCs. The sanitary

drains are therefore in the scope of 10 CFR 54.4(a)(2).^

The applicant stated that some of the roof drains are routed in such a way that they pass

directly over SR SSCs. A through-wall failure of these drains could lead to leakage upon

safety-reldted SSCs. Therefodre, these drains are within scope. The LW&Ds system would

process'any leakage, hbwever unlikely, frormthe r6of drains so that such leakage would not

cause a flood. ITherefore, only those'roof drains that ^are routed over safety-related SSCs can

adversely impact the performance of any safety-related SSCs, and only those drains are in the

scope of 10 CFR 54.4(a)(2). Roof drain components include the drain bodies, piping, and

closure bolting.

As a result of the reliance'on these components and the inclusion of the sanitary drains and the

roof drains in the LW&Ds system, the applicant added "drain bodies" and "pump casings" as

component types 'subject to an AMR in LRA Table'2.3.3.19. Accordingly, stainless steel tanks,

piping and components," pump casing, and cast iron'drain bodies should be added to the

LW&Ds aging management summary Table 3.3.2-19.-

2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19 and FNP FSAR Sections 9.3.3, 11.2 and 5.2.7. The

staff conducted its review,'using the'6valuation methodology described in Section 2.3 of this

SER, in accordance with the guidance described in Section 2.3 of NUREG-1800.

In its evaluation, the staff used the scoping process described in Section 2.3 of this SER to

review the'FSAR to determine if the applicant had identified all system functions in the LRA as

an intended function of the LW&Ds'system, in accordance with the requirements of

10 CFR 54.4(a). The staff did not identify any omissions. The staff then reviewed the FSAR, in

accordance with the screening process described in Section 2.3 of this SER, to verify that the

applicant had not omitted passive and long-lived components from an AMR, in accordance with

10 CFR 54.21(a)(1).

The staff's review of LRA' Section 2.3.3.19'identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.-

Therefore, by letter dated March'23, 2004, the staff issued RAI 2.0-2B, RAI 2.0-2C, RAI 2.0-2D,

and RAI 2.0-2E'and, by letter dated April 1, 2004,' the staff issued RAI 2.3.3.19-4 to determine

whether the applicant had 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, dated April 7, 2004, and April 29, 2004.

RAI 2.0-2B (D-RAI 2.3.3.19-1)

In the" LRA, the applicant stated that it evaluated running traps and floor drain plugs for aging

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effects. Table 2.3.3.19 of the LRA lists floor drain plugs as component types subject to an

AMR. However, LRA Table 2.3.3.19 does not list running traps as component types subject to

an AMR. The staff requested that the applicant justify the exclusion of running traps from an

AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

Applicant's Response and Staff's Evaluation

By letter dated April 7, 2004, the applicant responded that running traps, included in the

component type upiping" in LRA Table 2.3.3.19, are simply a U-shaped arrangement of pipe

and fittings designed to provide a water seal.

Based on its review, the staff finds the applicant's response to RAI 2.0-2B acceptable because

it clarifies that running traps are included in the component type "piping" as subject to an AMR,

in accordance with the requirements of 10 CFR 54.21(a)(1). Therefore, the staff considers RAI

2.0-2B resolved.

RAI 2.0-2C (D-RAI 2.3.3.19-2)

(a) In the LRA, the applicant stated that the containment cooler condensate level monitoring

subsystem is conservatively included within the scope of license renewal and credited in

the FNP CLB as a means to detect reactor coolant pressure boundary leakage as part

of the LBB analyses. The FNP FSAR states that the condensate measuring system

permits measurements of liquid runoff from the drain pans under each containment

cooler fan unit and consists of a vertical standpipe, valves, and standpipe level

instrumentation installed in the drain piping of the reactor containment fan cooler unit.

The staff could not find these vertical standpipes on the license renewal boundary

drawings. Therefore, the staff requested that the applicant confirm that these

standpipes are within the scope of license renewal and subject to an AMR, in

accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1),

respectively.

(b) License renewal boundary drawing D-205004L (Unit 2) shows two atmospheric vents at

locations El 1 and F8. The vent shown at location F8 is within the scope of license

renewal. However, the vent shown at location El 1 is excluded from the scope of license

renewal. The staff requested that the applicant clarify the intended function of these

vents and justify the exclusion of the latter vent from the scope of license renewal, in

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

(c) License renewal boundary drawings D-1 75004L (Unit 1) and D-205004L (Unit 2) show

containment cooler condensate drains within the scope of license renewal. However,

LRA Table 2.3.3.19 does not list these drains as component types subject to an AMR.

The staff requested that the applicant justify the exclusion of the containment cooler

condensate drains from an AMR in accordance with the requirements of

10 CFR 54.21 (a)(1). In addition, the staff requested that the applicant clarify if it

supplied containment cooler condensate drains with traps or screens to prevent

blockage in the standpipe.

(d) License renewal boundary drawing D-1 75004L shows a 3-in. atmospheric vent within

the scope of license renewal. License renewal boundary drawings D-175005L and

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D-205005L show two 2'in.:atmospheric vents within the scope of license renewal. Vents

are passive, long-lived components and are not listed in LRA Table 2.3.3.19 as a

component type subject to an AMR. The staff requested that the applicant justify the

exclusion of this component from an AMR, in accordance with the requirements of

10 CFR 54.21(a)(1).

Applicant's Response and Staff's Evaluation

(a) By letter dated April 7, 2004, the applicant responded that the standpipes are vertically

oriented piping and are part of the piping within the scope of license renewal upstream

of the level transmitters depicted on license renewal boundary drawings D-175004L

(Unit 1) and D-205004L (Unit 2). The applicant further stated that LRA Table 3.3.2-19

includes the standpipes in the component type "piping" as subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.0-2Ca acceptable,

because it identifies the location of the standpipes on 'the license renewal boundary

drawings and clarifies that the standpipes are within the scope of license renewal and

subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1), respectively. Therefore, the staff considers the concerns described

in RAI 2.0-2Ca resolved.

(b) By letter dated April 7, 2004, the applicant responded that the atmospheric vent for the

containment cooler condensate level monitoring subsystem on license renewal

boundary drawing D-205004L, at location El 1, is within the scope of license renewal

and should have been highlighted, similar to the vent shown at location F8. Table

2.3.3.19 of the LRA includes the vent piping in the component type upiping," with the

intended function of pressure boundary, and is subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.0-2Cb acceptable,

because the applicant concurred that the vent at location El 1 is within the scope of

license renewal and clarified that LRA Table 2.3.3-19 includes the vent in the

component type "piping" as subject to an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively. -Therefore, the staff considers

RAI 2.0-2Cb resolved.

(c) By letter dated April 7, 2004, the applicant responded that the drains for the containment

cooler drain pans comprise piping components (piping, fittings, etc.) and are subject to

an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1). The applicant

further stated that LRA Table 3.3.2-19 includes drains in the component type "piping" as

subject to an AMR. -No screens or traps are provided to prevent blockage in the

standpipe. - *

Based on its review, the staff finds the applicant's response to RAI 2.0-2Cc acceptable

because it clarifies that LRA Table 2.3.3-19 includes the containment cooler condensate

drains in the component type "piping" as 'subject to an AMR, in accordance with the

requirements of 10 CFR 54.21(a)(1). 'Therefore, the staff considers RAI 2.0-2Cc

resolved. - - . . - -.

(d) By letter dated April 7, 2004, the applicant responded that the atmospheric vents are

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I

passive, long-lived components that comprise piping that is open to the atmosphere.

The applicant further stated that vents are in the scope of license renewal and are

included in the component type "piping" in LRA Table 2.3.3.19 as subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.0-2Cd acceptable

because it clarifies that LRA Table 2.3.3-19 includes the atmospheric vents in the

component type "piping' as subject to an AMR, in accordance with the requirements of

10 CFR 54.21(a)(1). Therefore, the staff considers RAI 2.0-2Cd resolved.

RAI 2.0-2D (D-RAI 2.3.3.19-3)

License renewal boundary drawings D-175005L (Unit 1) and D-205005L (Unit 2) show the RCP

oil drip pan within the scope of license renewal. However, LRA Table 2.3.3.19 does not list the

reactor coolant oil drip pan as a component type subject to an AMR. The staff requested that

the applicant justify the exclusion of this component from an AMR in accordance with the

requirements of 10 CFR 54.21 (a)(1).

Applicant's Response and Staff's Evaluation

By letter dated April 7, 2004, the applicant responded that the RCP oil drip pans are subject to

an AMR and are included in the component type "tanks" in LRA Table 2.3.3.19 as subject to an

AMR.

Based on its review, the staff finds the applicant's response to RAI 2.0-2D acceptable because

it clarifies that LRA Table 2.3.3-19 includes the RCP oil drip pan in the component type "tanks"

as subject to an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1). Therefore,

the staff considers RAI 2.0-20 resolved.

RAI 2.3.3.19-4

The LRA does not list prevention of internal flooding as an intended function of the waste

disposal system. The staff requested that the applicant verify that the FNP internal flooding

analysis does not credit any of the floor drains, equipment drains, or waste disposal system

components.

Applicant's Response and Staff's Evaluation

By letter dated April 29, 2004, the applicant responded that the features of the LW&Ds systems

credited in the FNP's CLB, as described in FSAR Appendix 3K and Section 9.3.3, for the

prevention of internal flooding include sensors, which provide line break detection and sump

usage indication, and level alarms for the sumps in the lower elevations of the auxiliary building.

Section 9.3.3.3 of the FSAR provides the basis for the specific features relied upon in the CLB

to monitor sump usage and provide sump high level alarms.-

In its response, the applicant stated that in addition to the structural features of the rooms

(which include the sumps), the CLB credits the frequency of sump-pump operation, the number

of sump pumps operating, and the sump high level alarms for providing the operator with

indication of the leak. The scope of license renewal includes the sump pump controls and

sump level instrumentation under the plantwide electrical commodities. The level switches and

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mechanical alternators are acctive components and therefore do not require an AMR. The

sumps themselves and other physical features such-as curbing, pidtforms, equipment

pedestals,'ivalls, and watertight doors are included within the scope-of the license renewal

under the spaces approach used for civil/struictural 'commodities in LRA Section 2.5.

The applicant also clarified that it included the in-scope line break detection sensors assigned

to the LW&Ds system as part of the HELB detection system in LRA Section 2.3.3.17. These

line break'detection sensors are compartment/room pressure sensors that isolate the CVCS

letdown line in the event of a CVCS letd6wn line rupture.

During'review of the' intemal flooding prevention/mitigation scoping results for the LW&Ds

system in response to this'RAI, the applicant identified an omission in the LRA. Two rooms

evaluated for flooding in the CLB analysis utilize drain piping to'connect to a sump in an

adjoining area'that is relied upon to detect the lirie failure; The LRA omitted this interconnecting

piping. This nonsafety-related piping functionally supports the safety-related use of the sump to

detect a line failure and therefore is within the scope of license renewal, in accordance with the

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

The applicant further explained that for the first room, one of the drainlines is a 6-in.-diameter

stainless steel line that is routed through a-wall 'penetration to a fixed connection in the cover of

a sump in an adjoining room. The room (without the sump) is water tight, so a leak in the room

would fill the room'to'the height of the drain;'the drain would then fill the sump, and the sump

usage/level instrumentation would enable'the leak to be detected. The inlet of this drainline is

slightly miore'than 6 inches above the'floor (in the room without a sump), and the piping slopes

downward to the surMp cover to prevent water from jooling in the line;' Therefore, the drainline

'is dry during' normal operating conditions.'' -

For the second room, the applicant stated that the drainline connects the floor drain in the room

to a sump in an adjoining area. The room without a sump is a watertight room and any leak in

the room would pass through the drain to the sump, where instrumentation would enable

detection of the leak. This drain is 4 inches in diameter. One portion' of the drainline is made

from cast iron and the remainder, where the line enters the sump, is made from stainless steel.

Both-portions of the drainline are 'embedded in-concret6'.' This line is routed from the floor drain

to a point several feet above the bottom of the sump in the adjoining room and sloped to

prevent water pooling. Leakage in the room is normally insignificant, therefore this line is'dry

during normal operating conditions. " - I*'.

The applicant included these lines within the scope of license renewal because they directly

support the safety function of flooding detection. However, LRA Table 2.3.3.19 is unaffected,

since it already includes the applicable component types for these lines. Although the applicant

did not identify any credible aging'effect that could potentially result'in a'failure of the drain

piping (and surrounding concrete for one line) to direct flow to the sump; it stated that the

LW&Ds system AMR summary in LRATable 3.3:2-19 should have included the information

related to the above-mentioned in-scope drain lines.

Furthermore, the applicant explained that, in the event of a fire, drains are available to serve as

a support system to remove water used in fire'suppression (FSAR Section 9B.4.1.21).

However, the drains are a secondary support system to fire suppression. The waste disposal

system was neither designed nor installed in accordance with the design specifications for the

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1*

FP system. In scoping of SSCs for the regulated events of 10 CFR 54.4(a)(3), including FP

(10 CFR 50.48), consideration of hypothetical failures or second-, third-, or fourth-level support

systems is not required. This is consistent with the NRC's guidance on cascading for

10 CFR 54.4(a)(3), as described in-Table 2.1-2 of NUREG-1800. Therefore, the applicant did

not include floor drains, equipment drains, or other waste disposal system components in the

scope for the regulated event of a fire under 10 CFR 54.4(a)(3).

As part of their review of the implementation of the applicant's scoping and screening

methodology, as described in LRA Section 2.1, the NRC inspectors completed a license

renewal scoping and screening inspection on May 14, 2004. As a part of its consideration of

the applicant's response to RAI 2.3.3.19-4, the staff requested that the inspection team confirm

that no credible aging effect that could potentially result in a failure of the drain piping is

associated with the LW&Ds system drainlines, which were identified as within scope in the

applicant's response and subject to an AMR. As documented in Inspection Report |

50-348/2004-007, 50-364/2004-007, dated June 22, 2004, the inspector reviewed the RAI

response, verified the environmental conditions in the field, and concluded that, because of the

normally dry conditions of the piping, there was no credible aging effect, as stated in the

applicant's response to the RAI.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-4 acceptable

because it (1) adequately explains the features of the LW&Ds systems credited in FNP's CLB

for the prevention of internal flooding, (2) concurs that the drain piping that supports the use of

the sump to detect line failure is within the scope of license renewal, in accordance with the.

requirements of 10 CFR 54.4(a)(2), and (3) the inspection report verifies that there are no

credible aging effects that could result in a failure of the drain piping (and surrounding concrete

for one line) to direct flow to the sump. Therefore, the staff considers the concerns described in

RAI 2.3.3.19-4 resolved.

RAI 2.0-2E (D-RAI 2.3.3.19-5)

Section 2.3.3.19 of the LRA states that the compartment/room pressure sensors assigned to

the FNP LW&Ds system that isolate the CVCS letdown line in the event of a CVCS letdown line

rupture are addressed as part of the HELB detection system boundary. Section 2.3.3.17 of the

LRA states that the HELB system includes compartment/room pressure and level sensors for

the FNP LW&Ds system. However, the license renewal boundary drawings cited for the HELB

system do not refer to the LW&Ds system. The staff requested that the applicant clarify why it

did not list the LW&Ds system on the license renewal boundary drawings for the HELB system.

Applicant's Response and Staff's Evaluation

By letter dated April 7,2004, the applicant responded that Table B on HELB license renewal

boundary drawings D-175039L and D-205039L lists eight instruments with "G21" TPNS

designators. System G21 corresponds to the LRA system LW&Ds.

The applicant stated that the HELB detection instruments are listed in a tabular format because

there is no connected process piping. The system consists entirely of detection instruments

and the associated sensing lines. The instruments are shown within the scope of license

renewal on the HELB boundary drawings, assigned to the HELB detection system consistent

with the descriptions provided in LRA Sections 2.3.3.17 and 2.3.3.19, and are included on the

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license renewal boundary drawings referenced in'LRA Section 2.3.3.17.

Based on its review, the staff finds the applicant's response to RAI 2.0-2E acceptable because

the applicant has clarified that the license renewal boundary drawings refer to the "G21 0 TPNS

designator, which corresponds'tb'the LW&Ds s'ystem'' Th6refore;-the staff c6nsiders RAI 2.0-'

2E resolved. -

The staff finds the supplemental information related to 10 CFR 54.4(a)(2) in the June 4, 2004,

Enclosure 2 (discussed in Section 2.2.3) to be acceptable, on the basis that it adequately

identified all LW&Ds system's non-safety-related SSCs that are added to the scope of license

renewal as a result of the changed 10 CFR 54.4(a)(2) scoping methodology.

2.3.3.19.3 Conclusion" ' '

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal.

The staff found no ornissions.- In addition, the staff performed an independent assessment to

determine whether'th'e appli6ant identified 'all conponents that should be subject to an AMR.

The staff found noomissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the comriponents of the" LW&Ds system that are'within the scope of

license renewal, as required by'1 0 CFR 54.4(a),-and that the applicant has adequately

identified the components of the LW&Ds system that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.20 Oil-Static Cable Pressurization System

2.3.3.20.1 Summary of Technical Information in the Application

In Section 2.3.3.20 of the LRA, the applicant described the oil-static cable pressurization

system. The'oil-static cable pressurization system provides pressurized oil forthe oil-static

cables that are the feeder cables from the 230 kV switchyard to the startup auxiliary

transformers. The oil-static cable pressurization system keeps a static pressure of oil on these

underground cables. The oil insulates and cools the cables and minimizes cable corrosion.

The oil-static cable pressurization system consists of two pumping units,-with each-unit having

two pumps. Each pumping unit has a 1000-gallon-capacity oil supply tank, which has a

nitrogen cover gas. One pumping unit supplies the cables for startup auxiliary transformers 1 A

and 2B, and the other system supplies'the cables for startup auxiliary transformers 1 B and 2A.

The oil-static pump house in the switchyard houses the system components: The system is -

within the scope of license renewal because it supports operation of the in-scope offsite power

supply used to recover from an SBO event.

In Table 2.2-1 c of the'LRA, the applicant'identified the' following 10 CFR 54.4(a) criterion it used

to determine the oil-static cable pressurization system components that are within the scope of

license renewal: -' - - - - - -

station blackout (10 CFR 54.4(a)(3))

In Table 2.3.3.20 of the LRA, the applicant listed the oil-static cable pressurization system

component types that are within the scbpe of license renewal and subject to an AMR, including

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I

closure bolting, piping, pump casings, tanks, and valve bodies.

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20 and FNP FSAR Section 8.2.1.2. The staff conducted

its review, using the evaluation methodology described in Section 2.3 of this SER, in !

accordance with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff used the scoping process described in Section 2.3 of this SER to

review the FSAR to determine if the applicant identified all system functions in the LRA as an

intended function of the oil-static cable pressurization system, in accordance with the

requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff then

reviewed the FSAR, in accordance with the screening process described in Section 2.3 of this

SER, to verify that passive and long-lived components were not omitted from an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.20 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated December 12, 2003, the staff issued RAls 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 describes the staff's RAls and the applicant's responses,

dated January 9, 2004.

RAI 2.3.3.20-1

License renewal boundary drawing D-37281 6L shows magnetic level indicators within the scope

of license renewal. Magnetic level indicators provide the intended function of pressure

boundary and are not listed in LRA Table 2.3.3.20 as a component type subject to an AMR.

The staff requested that the applicant clarify if the pressure-retaining boundary of the magnetic

level indicators is subject to an AMR. If not, the staff requested that the applicant justify the

exclusion of these components from an AMR, in accordance with the requirements of

10 CFR 54.21(a)(1).

Applicant's Resvonse and Staff's Evaluation

By letter dated January 9, 2004, the applicant responded that the magnetic level indicator

consists of a vertical stainless steel pipe with a scale strapped to the outside, and a float inside.

Table 2.3.2.20 of the LRA includes the stainless steel pressure boundary subcomponents of the

magnetic level indicators in the component type "piping."

Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-1 acceptable

because it clarifies that LRA Table 2.3.2.20 includes the pressure boundary subcomponents of

the magnetic level indicators in the component type "piping" as subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1). Therefore, the staff considers the

concerns described in RAI 2.3.3.20-1 resolved.

RAI 2.3.3.20-2

(a) License renewal boundary drawing D-37281 6L shows unidentified components (1 RV2,

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1RV1, 2RV2, and 2RV1) W'ithin the s6ope'of license renewal: 'The license renewal P&ID

legend fordrawing D- 75016 does not list thiesecomponents." The staff requested that

the applicant identify these components'arid'clarify if they are'subject to an AMR.' If not,

the staff requested that the applicant justify the exclusion of these components from an

AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

(b) License renewal boundary drawing D-372816L-shows unidentified components 1 RD and

2RD excluded fromr the scope of license~rinew6l. The license renewal P&ID legend for

drawing D-1 75016 does not list these components. Although these components provide

an intended function of pressure' boundary, LRA Table 2.3.3.20 does not include them

as component types subject'to an AMR. The staff requested that the applicant identify

these components and clarify if they ar""within the'scope of license renewal and subject

to an AMR. if not, the staff requested that the applicant justify their exclusion from the

scope of license renewal and from a'n'AMR, in'accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21(a)(1), r6spectively.

ApDlicant's Resoonse and Staff's Evaluation

(a) By letter dated January 9, 2004, the applicant responded that it created the license

renewal boundary drawing for the oil-static cable pressurization system from a vendor

drawing. The'vendor did not use the 'standard symbolism depicted on the license

renewal drawing legend; therefore, some of the symbols and component identifiers on

the oil-static cable pressurization system are not standard. The applicant identified the

components addressed by this RAI as relief valves, and the component type "valve

bodies" in LRA Table 2.3.3.20 includes these relief valves as subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-2a

acceptable because it adequately identifies the components of the oil-static cable

pressurization system and clarifies that LRA'Table 2.3.3.20 includes these components

in the component type "valve bodies" as'subject to an AMR, in accordance with the

'requirements of 10 CFR 54.21 (a)(1). "'Therefore, the staff considers the concerns

described in RAI 2.3.3.20-2a resolved."'-!':

(b) By letter dated January 9, 2004, the applicant responded that it created the license

renewal boundary drawing for the oil-static cable pressurization system from a vendor

drawing.' The vendor did not us e 'standard symbolism depicted on the license'

renewal P&ID'legend; 'therefore, some' of the symbols and component identifiers on the

oil-static cable pressurization system are not standard. The applicant identified the

components (1 RD,'2RD) address6d by this RAI as rupture'disks (RDs). 'The applicant

stated that the oil storage tanks have a nitrogen cover gas applied to prevent moisture

intrusion,' not to provide pump suction'head, and an RD is provided to protect the tank

from overpressure. The applicant'concluded that since aging-related failure of the RD

could not prevent'the oil-static cable 'pressurization system from supplying oil to the-;

underground cables, the RDs are not within the scope of license renewal and an AMR is

not required.

Based on' its review; the'staff finds'the applicant's response to RAI 2.3.3.20-2b

acceptable because it adequately identifies the components of th6 oil-static cable' - -

pressurization system and clarifies'the exclusion of this component from the scope of

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license renewal and from an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively. Therefore, the staff considers

the concerns described in RAI 2.3.3.20-2b resolved.

2.3.3.20.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent assessment to

determine whether the applicant identified all components that should be subject to an AMR.

The staff did not identify any omissions.. On the basis of its review, the staff concludes that the

applicant adequately identified the components of the oil-static cable pressurization system that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

adequately identified the components of the oil-static cable pressurization system that are

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.21 Potable and Sanitary Water System

2.3.3.21.1 Summary of Technical Information in the Application

In Section 2.3.3.21 of the LRA, the applicant described the potable and sanitary water (P&SW)

system. For the purposes of license renewal, the P&SW system consists of the following FNP

systems:

* sanitary water system

* plant hot water heating system

The sanitary water system provides chlorinated or brominated water to the plant for drinking

and cleaning purposes. The plant hot water heating system carries water from the plant

heating system heat exchanger to various stations within the auxiliary building, including the air

handling unit heating coils. These systems are nonsafety-related but are within the scope of

license renewal, in accordance with the requirements of 10 CFR 54.4(a)(2), because of spatial

interaction with safety-related SSCs, and because portions of the plant hot water heating

system are high energy.

In Table 2.2-1 c of the LRA, the applicant identified the following 10 CFR 54.4(a) criterion it used

to determine the P&SW system components that are within the scope of license renewal:

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

In Table 2.3.3.21 of the LRA, the applicant listed the P&SW system component types that are

within the scope of license renewal and subject to an AMR, including closure bolting, heat

exchanger (channel head), heat exchanger (shell), piping, strainers (shell), tanks, and valve

bodies.

In its response to RAI 2.1-1 (discussed in Section 2.1 of this SER), the applicant changed the

methodology used for scoping of unattached, nonsafety-related piping for the P&SW system, in

accordance with 10 CFR 54.4(a)(2). By letter dated June 4, 2004, the applicant submitted the

supplemental information associated with the determination of SSCs within the scope of license

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renewal, in accordance with the requirements of 10 CFR 54.4(a)(2), as a result of the changed

scoping methodology (see'Enclosure 2, "Joseph M.' Farley Nuclear-Plant Units 1 Sand 2,

Application for License Renewal, Sipplementtal lnforriation Related to 10 CFR 54.4(a)(2)").

The methodology change expanded the rnechanical SSCs within the scope of licenrse renewal.

In its supplemental information related to 1 CFR 54.4(a)(2), the applicant listed the impact of'

changes in the 10 CFR 54.4(a)(2) scoping methodology on the LRA results of the in-scope

components for P&SW system. Although this table shows an increase in the'in-scope SSCs for

the P&SW system, the applicant stated that the'eom`0onent types do not change from the

component types listed in LRA Table 2.3.3.21

2.3.3.21.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.21'and FNP FSAR Section 9.2.4. The staff conducted its

review, using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff used the scoping process described in Section' 2.3 of this SER to

review the FSAR to determine if the applicant'idehtified all system functions in the LRA as an

intended function of the P&WS system, in accordance with the requirements of 10 CFR 54.4(a).

The staff did not identify any omissions. Th6 staff then conducted a review, in accordance with

the screening 'Process described in Section 2.3 of this SER, to verify that the applicant did not

omit passive and long-lived components from an AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.21 identified an area in which it needed additional

information to complete the evaluation of the' applicant's scoping and screening results.'

Therefore,- by letter dated March 23, 2004, the staff issued an RAI 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 describes the staff's RAI and the applicant's response,

dated April 7, 2004.

RAI 2.3.3.21-1

The P&SW system is non-safety-related bu4tiswithin the scope of license renewal because of

the potential for spatial interaction with safetyrelated components, per 10 CFR 54.4(a)(2).

Table 2.3.3.21 of the LRA lists the componient type's subject to an-AMR. However, LRA Section

2.3.3.21 does not provide or refere`66 any license renewal boundary drawings associated with

the P&SW system. Section 9.2.4.2of the FNP FSARstates'that drawing D-170127 shows the

P&ID for the P&SW system. However, the'applican't did not provide this-drawing to the staff for

review.

The staff requested that the applicant provide a description or license renewal boundary

drawing to identify the components of the P&SW system that are within the scope of license

renewal and subject to an AMR, in accordan'ceWith the requirements of 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1), respectively.

Apolicant's Response and Staff's Evaluation"

By letter dated April 7, 2004, the applicant responded that the P&SW system includes the

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II

sanitary water system and plant hot water heating system. The sanitary water system supplies

domestic water for use throughout the plant. The plant hot water heating system carries water

for the plant heating system heat exchanger to air handling heating coils located throughout the

auxiliary building. The plant hot water heating system is within scope for high-energy line

consideration, and other portions of the P&SW system are within the scope of license renewal

for spatial interaction, in accordance with 10 CFR 54.4(a)(2).

In response to the staff's request to identify the components of the P&SW system that are

within the scope of license renewal and subject to an AMR, the applicant stated that LRA Table

2.3.3.21 lists the component types subject to an AMR, and LRA Table 3.3.2-21 identifies the

applicable material and environment combinations for these components. The applicant further

listed closure bolting, piping components (piping, fittings, etc.), valves, heat exchangers,

strainer (shell), and tanks for the in-scope portion of plant hot water system. The applicant

stated that the in-scope portion of the sanitary water system within the scope of license renewal

includes closure bolting, piping components (piping, fittings, etc.), valves, and tanks.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1 acceptable

because it adequately identifies the intended function of the subsystems of the P&SW system

(sanitary water system and plant hot water heating systems) and also lists the components of

the plant hot water heating and sanitary water systems that are within the scope of license

renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1), respectively. Therefore, the staff considers the concerns described in RAI

2.3.3.21-1 resolved.

The staff finds the supplemental information related to 10 CFR 54.4(a)(2) in the June 4, 2004,

Enclosure 2 (discussed in Section 2.2.3) to be acceptable, on the basis that it adequately

identified all P&SW system's non-safety-related SSCs that are added to the scope of license

renewal as a result of the changed 10 CFR 54.4(a)(2) scoping methodology.

2.3.3.21.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent assessment to

determine whether the applicant identified all components that should be subject to an AMR.

The staff found no omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the P&SW system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the P&SW system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.22 Radiation Monitoring System

2.3.3.22.1 Summary of Technical Information in the Application

In Section 2.3.3.22 of the LRA, the applicant described the radiation monitoring system. The

radiation monitoring LRA system consists of the FNP process and area radiation monitoring

systems. The radiation monitoring systems at FNP are grouped into three categories:

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* process and effluent radiological monitoring, which includes both continuous process

and periodic sampling systems

* area radiation monitoring, which monitors radiation fields in various areas within the

plant '' -

* airborne radioactivity monitoring, which monitors specific areas of the plant to ensure

that in-plant airborne radioactiVermiaterials concentrations are-controlled during normal

plant activities, such that limits stated in 10 CER Part 20 will not be exceeded

The airborne radioactivity monitoring is a nonsafety-related function that is not within the scope

of license ren 'Wal. The process' and bfflueit 'radiol6gical monitoring portion of the system is

used to monitor process and effluent strea~iis during normal operations and postulated: -

accidents to provide indication and record releases of radioactive materials generated and to

initiate automatic system responses. Thd ii-s-cope portions a're addressed as part of the'

system that includes the process or effluent'being 'monitored.

Area radiation monitors are standalone rno-nitors'and addressed in the scoping and screening

results for the ele6trical and I&C systems'along with'the-process and effluent radiological

monitors.

In Table 2.2-1 c of the LRA, the applicant identified the following 1 0 CFR 54.4(a) criteria used to

determine the radiation monitoring system components that are within the scope of license'

renewal:

* -safety-related (10 CFR 54.4(a)(1))

* 'environmental qualification (10 CFR 54.4(a)(3))

2.3.3.22.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.22 and FNP FSAR Sections 11.4 and 12.2.4. The staff

conducted its review, using the evaluation methodology described in Section 2.3 of this SER, in

accordance-with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff used the" scoping process described in' Section 2.3 of this SER to

review the FSAR to determine if the'applicant identified all system functions in the LRA as an

intended function of the radiation monitoring system, in accordance with the requirements of

10 CFR 54.4(a). The staff did not identify any omissions. The staff then reviewed the FSAR, in

accordance with the screening process described in Section 2.3 of this SER, to verify that the,

applicant did not omit passive and long-lived components from an AMR, in accordance with

10CFR54.21(a)(1). '- ; - -

The staff's review of LRA Section 2.3.3.22 identified an'area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results. '

Therefore, by letter dated March 23, 2004, the staff issued an RAI 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 describes the staff's RAI and the applicant's response,

dated April 7, 2004. '

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RAI 2.3.3.22-1

Section 2.3.3.22 of the LRA states the following:

The process and effluent radiological monitoring portion of the radiation monitoring

system is used to monitor process and effluent streams during normal operations and

postulated accidents to provide indication and record releases of radioactive materials

generated and to initiate automatic system responses. The in-scope portions are

addressed as part of the LRA system that includes the process or effluent being

monitored.

The in-process radiation monitoring elements shown on the license renewal boundary drawings

for the closed-cycle cooling water and open-cycle cooling water systems are installed in line

and,- therefore, serve the intended function of pressure boundary. However, the applicant did

not list these components in the LRA tables as subject to an AMR. Section 2.3.3.22 of the LRA

does not list the systems that contain the process or effluent being monitored, nor does it

reference any boundary drawings associated with the radiation monitoring system. Therefore,

the staff could not confirm that the SSCs meeting the requirements of 10 CFR 54.4(a) are

included within the scope of license renewal. The staff requested that the applicant provide a

list of the LRA systems which includes the process or effluent being monitored by components

of the radiation monitoring system.

ApDplicant's Response and Staff's Evaluation

By letter dated April 7, 2004, the applicant stated that the radiation monitors installed in line on

an in-scope portion of a process system serve the intended function of pressure boundary and

are therefore within the scope of license renewal. The scoping results for the mechanical

system being monitored include these radiation monitors. The applicant also clarified that, for

radiation monitors installed in line on an in-scope portion of a process system, the items are

treated the same as piping or ductwork fittings and are included in the component type "piping"

for piping applications, and in the component type "ducts and fittings" for ventilation

applications, and are subject to an AMR.

In response to the staff's request, the applicant developed a table which lists the LRA systems

that includes the process or effluent being monitored by components of the radiation monitoring

system. This table lists those radiation monitors that are part of a mechanical LRA system's inscope pressure boundary.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.22-1 acceptable

because it adequately identifies the systems which include the process or effluent monitored by

components of the radiation monitoring system and clarifies that, for radiation monitors installed

in line on an in-scope portion of a process system, the items are subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1). Therefore, the staff considers RAI

2.3.3.22-1 resolved.

2.3.3.22.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal.

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The staff found no omissions. In' addition, the staff performed an i:dependent assessment to

determine whether the applicant identified all components that should be subject to an AMR.

The staff found no omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the radiation monitoring system that are within the

scope of license renewal, as required by '10 CFR 54:4(a), and that the applicant adequately

identified the components of the radiation monitoring system that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.23 Reactor-Makeup Water Storage System

2.3.3.23.1 Summary of Technical Information in the Application

In Section 2.3.3.23 of the LRA, the applicant described the reactor makeup water storage

(RMWS) system. The RMWS system provides nonborated makeup water for the RCS and

makeup and flushing water for various other components. The RMWS system provides an

assured seismic Category I makeup source to the component cooling water system surge tank

and to the SFP as its license renewal intended function.

In Table 2.2-1 c of the LRA,' the applicant identified the following .10 CFR 54.4(a) criteria met by

the reactor makeup -water system components which are within the scope of license renewal:--

* 'safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

In Table 2.3.3.23 of the LRA, the applicant listed'the RMWS system component types that are

within the scope of license renewal and subject to an AMR, including closure bolting, flow

orifice/element, piping, pump casings, tanks,-and valve bodies.

In its response to RAI 2.1 -1 (discussed in Section 2.1 of this SER), the applicant changed the

methodology used for scoping of unattached, nonsafety-related piping for the RMWS system in

accordance with 10 CFR 54.4(a)(2). By letter dated June 4, 2004, the applicant submitted the

supplemental information associated with the determination of SSCs within the scope of license

renewal, in accordance with the requirements of 10 CFR 54.4(a)(2), as a result of the changed

scoping methodology (see Enclosure 2, "Joseph M. Farley Nuclear Plant Units 1 and 2,

Application for License Renewal, Supplemental Information Related to 10 CFR 54.4(a)(2)").

The methodology change expanded the -mechanical SSCs within the scope of license renewal.

In its supplemental information related t6 10 CFR 54.4(a) (2) the applicant listed the impact of

changes in the 10 CFR 54.4(a)(2) scoping "methodology 'on the LRA results of the in-scope

components for the RMWS system. Although this table shows an increase in the in-sco'pe

SSCs for the RMWS system,,'the applicant stated that the component types do not change from

the component types listed in LRA Table 2.3.3.23.--

2.3.3.23.2 Staff Evaluation .-

The staff reviewed LRA'Section 2.3.3.23 and FNP FSAR Sections 9.2.7, 9.3.4, 9.1.3.3, and

9.2.2.2. The staff bonducted its review, using the evaluation methodology described in Section

2.3 of this SER, in accordance with the guidance described in Section 2.3 of NUREG-1 800.

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In its evaluation, the staff used the scoping process described in Section 2.3 of this SER to

review the FSAR to determine if the applicant had -not identified all system functions in the LRA

as an intended function of the RMWS system, in accordance with the requirements of

10 CFR 54.4(a). The staff did not identify any omissions. The staff then reviewed the FSAR, in

accordance with the screening process described in Section 2.3 of this SER, to verify that the

applicant did not omit passive and long-lived components from an AMR, in accordance with

10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.3.23 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff issued RAls 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 describes the staff's RAls and the applicant's responses,

dated April 22, 2004.

RAI 2.3.3.23-1

In FNP FSAR Section 9.2.7.2.1, the applicant stated that the RMWS tank contains a diaphragm

membrane, and the Unit 1 tank contains a 150-gal/min recirculating vacuum degasifier to

exclude oxygen from the makeup water. License renewal boundary drawings D-175036L,

D-205036L, D-17011 8L, and D-200012L depict the diaphragm as used in the reactor water

makeup and condensate storage tanks (CSTs). License renewal boundary drawing D-205036L

shows the diaphragm within the scope of license renewal. However, license renewal boundary

drawings D-1 75036L, D-170118L, and D-200012L exclude the diaphragm from the scope of

license renewal. In addition, LRA Table 2.3.3.23 does not list these diaphragms as component

types subject to an AMR. These diaphragm membranes provide an intended function of

pressure boundary for the RMWS tanks and are passive, long-lived components. The staff

requested that the applicant justify the exclusion of the RMWS tank diaphragms for Units 1 and

2 (with the exception of the one shown on license renewal boundary drawing D-205036L) from

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

addition, the staff requested that the applicant explain why LRA Table 2.3.3.23 does not list

these components as component types subject to an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1).

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the stainless steel RMWS tanks

contain a diaphragm membrane that excludes oxygen from the makeup water. These

diaphragms do not perform an intended function for license renewal.

The applicant added that the failure of the diaphragm would not result in the loss of any safetyrelated function. Should the diaphragm become perforated, the reactor makeup water in the

tank remains available to provide adequate makeup to the closed-cycle cooling water surge

tank and SFP. The tank and connecting piping provides the pressure boundary for the RMWS

systems. The applicant concluded that boundary drawings D-175036L, D-170118L, and

D-200012L correctly show the diaphragm as excluded from the scope of license renewal.

However, boundary drawing D-205036L incorrectly highlighted the diaphragm as within the

scope of license renewal.

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During a telephone conference on May 24, 2004, between the applicant and the NRC staff, the

staff requested that the applicant clarify whether the disintegration bf the diaphragm membrane

could cause blockage of the supply lines from the RMWS tanks to the closed-cycle cooling

water system.

By letter dated June 18, 2004, the applicant, in its revised response, stated that the diaphragm

membranes would not degrade (disintegrate) to the point where blockage of the supply lines

could occur. In-its response, the applicant stated that, although these nonsafety-related

diaphragms would not fail in a manner-that would prevent accomplishment of a safety-related

function, the applicant's review of the industry and site-specific operating experience identified

that age-related degradation of elastomer-type tank diaphragms is a reasonable expectation for

the period of extended operation. At FNP, the applicant has replaced these tank diaphragms

with diaphragms made'of improved materials due to degradation. Therefore, the applicant

decided to' include the tank diaphragms in'an aging management program (AMP) to provide

additional assurance.

The'applicant expanded the scope of this response to include the diaphragm membranes of the

CSTs and the boric acid tanks, in addition to the RMWS tanks, because these tanks are within

the scope of license renewal and have similar elastomer diaphragms subject to the same

concern. 'The AFW system (LRA Section 2.3.4.4) includes the CSTs, and the CVCS (LRA

Section 2.3.3.8) includes the boric acid tanks. Therefore, the applicant concurred that LRA

Tables 2.3.3.8, 2.3.3.23, and 2.3.4.4 should have included the tank diaphragms as a

component type within the scope of license renewal and subject to an AMR. As a result, the

applicant also provided additional information to supplement the scoping, AMR results, and

AMP discussions in the application.

Based on its review,'the staff finds the applicant's revised response to RAI 2.3.3.23-1

acceptable because-it concurred that the diaphragm membranes in the RMWS tanks should

have been within the scope of license renewal and subject to an AMR, in accordance with the

requirements of 10 CFR 54.4(a)' and 10 CFR 54.21 (a)(1), respectively. Therefore, the staff

considers RAI 2.3.3.23-1 resolved. -

RAI 2.3.3.23-2 -

(a) License renewal boundary drawings D-1 701 18L and D-200012L show a 3-in. ventline

(HCD-262) and a 3-in. nitrogen purge line (HCD-263) excluded from the scope of --

license renewal. These lines serve the intended function of pressure bouridary. The

staff requested that the applicant justify the exclusion of these lines from the scope of

license'renewal and from an AMR, in accordance with the requirements of

10 CFR'54.4(a) and 10 CFR 54.21 (a)(1), respectively. -

(b)' License renewal boundary drawings D-170118L and D-200012L show 1-in. pipelines,

'6bnnected to a level controller (MK274 and MK774) excluded from the scope of license

' renewal.' These lines serve the intended function of pressure boundary. -The staff

requested that the applicant justify the exclusion of these lines from the scope of license

renewal and from an AMR, in accordance with the requirements of 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1), respectively.

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Applicant's Response and Staff's Evaluation

(a) By letter dated April 22, 2004, the applicant responded that tank connections for the

3-in. ventline and the 3-in. nitrogen purge line are used during the filling operation of the

RMWS tank to evacuate air underneath the diaphragm. These lines are located 3'-6u'

above the normal water level in the tank and do not provide a pressure boundary for the

required inventory of the reactor makeup water in the tank. Therefore, they are

excluded from the scope of license renewal and from an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-2a

acceptable because it adequately explains the basis for excluding the ventline and the

nitrogen purge line from the scope of license renewal and from an AMR, in accordance

with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively.

Therefore, the staff considers the concerns described in RAI 2.3.3.23-2a resolved.

(b) By letter dated April 22, 2004, the applicant responded that, through further evaluation

of the level controller lines addressed in the RAI, it has determined that these lines

serve the intended function of pressure boundary, relative to maintaining the pressure

boundary of the RMWS tank, and are within the scope of license renewal. The applicant

also stated that the 1-in. stainless steel piping and the level controllers are the only

component types in these lines. The level controllers are not subject to an AMR since

they are active components. However, the piping is passive and long-lived and is

already identified in LRA Table 2.3.3.23 as a component type subject to an AMR with

the intended function of pressure boundary.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-2b

acceptable because the applicant concurred that the level controller lines addressed in

the RAI are within the scope of license renewal and are included in LRA Table 2.3.3.23

in the component type "piping" as being subject to an AMR, in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively. The applicant

also clarified that the level controllers are active components and are therefore not

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

Therefore, the staff considers RAI 2.3.3.23-2b resolved.

RAI 2.3.3.23-3

License renewal boundary drawings D-175036L and D-205036L show the license renewal

boundary for this system to end at valves Q1 G22V063A, Q1 G22V063B, Q2G22V063A, and

Q2G22V063B. These valves appear to be normally open, and a piping class change occurs at

this valve. Normally open manual valves can be used as a license renewal pressure boundary

if failure of the downstream piping has no short-term effects, can be quickly detected, and will

be closed by the operators before any adverse consequences occur. The staff requested that

the applicant explain why it is acceptable to terminate the license renewal boundary at these

normally open valves.

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the piping associated with the open

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valves identified in the RAI consists of reactor makeup water providing seal water to the waste

gas compressor (WGC). This reactor makeup water supply to the WGC is not an in-scope

function for the system. The waste processing system has'no safety-related function, and there

are no in-scope functions for the waste gas system. The valve alignment depicted on the

boundary drawing assumes the system is aligned to support waste gas system operation.

The applicant added that the RMWS system is within the scope of license renewal as a-source

of long-term makeup water for the component cooling water system surge tank and for the

SFP. The makeup supply from'the RMWS system to the component cooling water surge tank,

addresses loss of inventory from minor leakage sources during long-term postaccident recoveIry

in the event the demineralized water system is unavailable. The use of the RMWS system for

makeup water to the'SFP by the use of the temporary hose connection is also a long-term;

recovery action in the unlikely event of a failure'of both safety-related trains of the SFP, cooling

system and the demineralized water system. - -

In response to the staff's request to explain why it is acceptable to terminate the license,

renewal boundary at these normally open valves, the applicant explained that the 3/4-in. piping

downstream of the isolation valves (Q2G22V063A and Q2G22V063B) is located outside of the

WGC rooms as well as inside the rooms. Failure of this line has no short-term effects--ithe,

WGC equipment is not safety-related, and there is no short-term need for makeup water to the

component cooling water surge tank or SFP.- I --

The applicant also stated that the detection of the leak depends on the size of the leak. In the

event of a complete failure equivalent to a 3/4-in. line break, the flow out of the break would

reduce the level in the RMWS tank slowly, given the large capacity of the tank (approximately

200,000 gallons). The unusual increase in waste tank/sump levels or from the changes in

RMWS tank level and associated alarm readings would lead to detection of the reduction in

level. -The leak would be isolated before any inventory loss that would occur would compromise

the intended function of the RMWS because of the large capacity of the RMWS tank and the

scmall size of the potential leak (3/4 in.). :.

Based on its review, the'staff finds the applicant's response to RAI 2.3.3.23-3 satisfactory,

because it adequately'explains that it is acceptable to terminate the license renewal boundary

at the normally open valves addressed in the RAI because failure of 3/4-in. piping downstream

of the isolation valves (Q2G22V063A and Q2G22V063B) would not compromise the intended

function of the RMWS system. Therefore, the staff considers RAI 2.3.3.23-3 resolved.

As part of its review of the implementation of .the applicant methodology, as described in LRA

Section 2.1, the NRC inspectors completed a license renewal scoping and screening inspection

on May 14, 2004, which is documented in Inspection Report 50-348/2004-007,

50-364/2004-007, dated June 22, 2004.- The inspection consisted of a selected examination of

procedures and representative records and interviews with personnel regarding the process of

scoping'and screening plant components to select components subject to an AMR.

Additionally, the NRC inspectors performed a walkdown of selected areas of the plant ..-- containing SSCs that are considered to be within the scope of license renewal because they

meet the '-10 CFR 54.4(a)(2) requirement. ,For a sample of plant systems, specificallythose that

the NRC reviewers identified, the NRC-inspectors performed visual inspection of accessible

portions of the systems to observe any effects of component aging.

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The inspectors concluded that the applicant had successfully performed scoping and screening

and identified the SCs subject to an AMR, in accordance with the methodology described in the

LRA and the license renewal rule, with the following exception.

The inspectors noted that boundary drawings were inconsistent on various drawings in

depicting the atmospheric vents for the refueling water storage, condensate storage, and the

RMWS tanks as in or out of the scope of license renewal.

By letter dated July 9, 2004, the applicant provided supplemental information to the

atmospheric vents on the RWSTs, CSTs, and RMWS tanks. In this supplement, the applicant

agreed to include these vents in the scope of license renewal. The applicant stated that these

vent lines are considered an integral subpart of the tanks and, consequently, are lumped into

the existing utank" component type. Therefore, the component types in the AMR tables in the

corresponding LRA scoping sections are unaffected. However, the applicant stated that the

AMR summary tables should have included additional material-environment combinations for

the tanks as a result of bringing the tank vents into scope and provided the additions to the

corresponding AMR summary tables.

The staff finds the supplemental information related to 10 CFR 54.4(a)(2) in the June 4, 2004,

Enclosure 2 (discussed in Section 2.2.3) to be acceptable, on the basis that it adequately

identified all RMWS system's non-safety-related SSCs that are added to the scope of license

renewal as a result of the changed 10 CFR 54.4(a)(2) scoping methodology.

2.3.3.23.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent assessment to

determine whether the applicant identified all components that should be subject to an AMR.

The staff found no omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the RMWS system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the RMWS system that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.24 Sampling System

2.3.3.24.1 Summary of Technical Information in the Application

In Section 2.3.3.24 of the LRA, the applicant described the sampling system. The sampling

system is designed to permit liquid and gaseous sampling for analysis and chemistry control of

the plant primary and secondary system fluids. It allows the needed samples to be obtained

under both normal operation and shutdown conditions. Portions of the system also support

postaccident sampling.

Portions of the system that are within the scope of the license renewal rule support the pressure

boundary function-of the safety-related system being sampled, provide containment isolation

where the sample system penetrates the containment boundary, and/or provide manual

sampling to ensure that the boration to cold shutdown margin is achieved for safe shutdown

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under Appendix R to 10 CFR Part 50. In addition, the sample lines for SGBD, the pressurizer,

and the reactor coolant hot leg isolate automatically on high penetration room pressure to

support maintaining the negative pressure required for the penetration room filtration (PRF)

function. --

In Table 2.2-1c of the LRA,'the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the sampling system components'that'are within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

In Table 2.3.3.24 of the LRA, the applicant'listed the sampling system component types that are

within the scope of license renewal and subject to an AMR, including closure bolting, heat -

exchanger' (shell),' heat exchanger (tubes),;pipirig, and valve bodies.- .-

2.3.3.24.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.24 and FSAR Section 9.3.2. The staff conducted its

review, using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff used the scoping process described in Section 2.3 of this SER to

review the FSAR t6'deterrnine if the applicant identified all system functions in the LRA as an

intended function of the sampling system, in accordance with the requirements of

10 CFR 54.4(a). The 'staff did not identify any omissions. The staff then reviewed the FSAR, in

accordance'with''th screening process described in Section 2.3 of this SER,-to verify that the

applicant had notfomitted passive and long-lived components from an AMR, in accordance with

10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.24 identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff issued an RAI determine whether the

applicant had 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 RAI and the applicant's response,

dated April 22, 2004.

RAI 2.3.3.24-1

License renewal boundary drawings D-1 75009L and D-205009L show gross failed fuel

detectors within the scope of license renewal. However, LRA Table 2.3.3.24 does not list gross

failed fuel detectors as a component type subject to an AMR. The gross failed fuel detector

housiig'serves the intended function of pressure boundary and is within the scope of license

renewal. 'The staff requested that the 'applicant clarify if the pressure boundary retaining

corponents of the gross failed fuel detectors are subject to an AMR. If not, the staff asked the

applicant to justify their exclusion from an AMR, in accordance with the requirements of

10 CFR 54.21 (a)(1). '- r

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II

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that the gross failed fuel detector is an

assembly with the pressure boundary component types individually scoped, screened, and an

AMR performed. The subcomponents of the gross failed fuel detector assembly (with

component type indicated in parentheses) that provide a pressure boundary function include

tubing (piping), valves (valve bodies), sample cooler tubing (sample cooler heat exchanger

tubes), and neutron detector coil tubing (piping). Tables 2.3.3.24 and 3.3.2-24 of the LRA

include these components under the component types indicated.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.24-1 acceptable

because it adequately identifies the subcomponents of the gross failed fuel detector assembly

that serve the intended function of pressure boundary and clarifies that LRA Table 2.3.24

includes these subcomponents in the component types upiping," "valve bodies," and "sample

cooler heat exchanger tubes" as subject to an AMR, in accordance with the requirements of

10 CFR 54.21(a)(1). Therefore, the staff considers the concerns described in RAI 2.3.3.24-1

resolved.

2.3.3.24.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant did not identify all SSCs that should be within the scope of license

renewal. The staff found no omissions. In addition, the staff performed an independent

assessment to determine whether the applicant identified all components that should be subject

to an AMR. The staff found no omissions. On the basis of its review, the staff concludes that

the applicant has adequately identified the components of the sampling system that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the components of the sampling system that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.4 Steam and Power Conversion Systems

This section addresses the staff's review of the results of the scoping and screening

methodology for steam and power conversion systems, which consist of the following:

* main steam system

* feedwater system

* steam generator blowdown system

* auxiliary feedwater system

* auxiliary steam and condensate recovery system

* turbine and turbine auxiliaries

In accordance with the requirements stated in 10 CFR 54.21(a)(1), the applicant must identify

and list SCs subject to an AMR. These are passive, long-lived SCs that are within the scope of

license renewal. To verify that the applicant properly implemented its methodology, the staff

reviewed the scoping and screening results to confirm that the applicant did not omit any

mechanical system components that are subject to an AMR.

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2.3.4.1 Main Steam System

The main steam LRA system comprises the main steam system, auxiliary steam system, and -

portions of the feedwater control system.

2.3.4.1.1 Summary of Technical Information in the Application

In Section 2.3.4.1 of the LRA, the applicant described the main steam LRA system. The main

steam system conducts steam from the steam generators to the turbine generator and to

supporting componernts,'including the MSRs, stear'n jet air ejectors, gland sealing steam

system, auxiliary steam system,' and steanm 'generator feed pump-turbiries. :The 'niairi steam

system-also supplies steam via the auxiliary' steaim system to the turbine-driven AFW pump.'

The pdrtions'of the main steam system from each steam generator, up to and including theMSIVs and the supply to the turbine-driven AFW pump, are necessary for the safe shutdown of

the plant and accident mitigation.

The main steam LRA system boundary includes the level and flow instrumentation attached to

the steam generator, although otherwise classified as part of the feedwater control system, - - because it forms part of the main steam system pressure boundary and provides input to the

reactor protection system.

The first-stage turbine impulse pressure sensing lines and associated transmitters provide input

to the reactor protection system and ATWS mitigation'system actuation circuitry (for mitigation

of an ATWS event) and are included in the'scope of the main steam system boundary.

The applicant addressed the compartment/room pressure sensors, provided in areas affected

by a rupture of an auxiliary steam supply line to the turbine-driven AFW pump and assigned to

the auxiliary steam system, separately as part of the HELB detection LRA system boundary.

In Table 2.2-1 d of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria used to

determine the main steam LRA'system' corrpo'nnits that are within the scope of license

renewal:

safety-related (10 CFR 54.4(a)(1)) ' f'' t f:

non-safety-related that can prevent a safety-related function'(10 CFR 54.4(a)(2))

fire protection (10 CFR 54.4(a)(3))

environmental qualification (10 cCFR 54.4(a)(3))'

* anticipated transient withbot scram (10 CFR 54.4(a)(3))

In Table 2.3.4.1 of the LRA, the applicant listed the main steam system component types that

are within the scope of license renewal and subject to an AMR, including closure bolting, flow

orifice/element, piping, steam/fluid traps, turbine pump drive casings, and valve bodies. - b . i .. ; . .- . .. , . *t

2.3.4.1.2 Staff Evaluation ' '' ' : -' " - -

The staff reviewed LRA Section 2.3.4.1 'and FNP FSAR Sections 10.1, 10.3, and 7.8.' The staff

conducted its review, using the evaluation methodology described in Section 2.3 of this SER, in

accordance with the guidance described in Section 2.3 of NUREG-1800.

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In its evaluation, the staff used the scoping process described in Section 2.3 of this SER to

review the FSAR to determine if the applicant had identified all system functions in the LRA as

an intended function of the main steam system, in accordance with the requirements of

10 CFR 54.4(a). The staff did not identify any omissions. The staff then reviewed the FSAR, in

accordance with the screening process described in Section 2.3 of this SER, to verify that the

applicant had not omitted passive and long-lived components from an AMR, in accordance with

10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.1 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff issued RAls determine whether the

applicant had 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,

dated April 23, 2004, and June 18, 2004.

RAI 2.3.4.1

License renewal boundary drawings D-175033L and D-205033L show air reservoirs within the

scope of license renewal. Air reservoirs serve the intended function of pressure boundary and

are passive, long-lived components. However, LRA Table 2.3.4.1 does not include air

reservoirs as a component type subject to an AMR. The staff concluded that the air reservoirs

serve a pressure boundary intended function and are passive, long-lived components. The

staff requested that the applicant justify the exclusion of air reservoirs from an AMR, in

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

Applicant's Response and Staff's Evaluation

By letter dated April 22,2004, the applicant responded that these air reservoirs are an integral

part of the valve operator, directly support the active function of the operator, and are included

as part of the valve operator component for license renewal. The valve operator only performs

an active function and, therefore, is not subject to an AMR. Age-related degradation of the

valve operator is managed under the requirements of the Maintenance Rule.

During a telephone conference between the applicant and the NRC staff on May 24, 2004, the

staff agreed to consolidate RAI 2.3.3.5-1a, RAI 2.3.3.5-1 b, RAI 2.3.4.1-1, and portions of RAI

2.2-5b for the pneumatic valve operator air tanks to a revised RAI 2.2-5b, since the applicant's

responses to these RAls were related to the integral parts of valve operators. Therefore, by

letter dated June 25, 2004, the staff issued the revised RAI 2.2-5b. Section 2.2.3 of this report

describes the revised RAI 2.2-5b, the applicant's response, and the staff evaluations.

RAI 2.3.4.1-2

Table 2.3.4.1 of the LRA lists steam/fluid traps as a component type subject to an AMR.

However, the only steam/fluid traps appearing on the license renewal boundary drawings

D-175033L and D-205033L are excluded from the scope of license renewal. The'staff

requested that the applicant identify the in-scope steam traps referred to in LRA Table 2.3.4.1.

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; s : a Aplc St ' a - f f s -Evaluaton -

Applicant's'Response and Staff's Evaluation' - -' - '

By letter dated April 22, 2004, the applicant responded that the steam traps listed in LRA Table

2.3.4.1 are solely within the scope of license renewal under 10 CFR 54.4(a)(2) and, as such, :

are not highlighted on the license renewal boundary drawings. The applicant also provided the

identificationhnumbers for eight steam traps (p6r unit)'within the scope of license renewal and

shown on license renewal boundary drawings referented in LRA Section 2.3.4.1.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-2 acceptable

because it adequately explains that the steam traps are not highlighted on the license renewal

boundary-drawings'because they are within scope solely in accordance with 10 CFR 54.4(a)(2).

The applicant then'specifically identifies the in-scop-e'steam traps on these drawings.

Therefore, the staff considers the concerns describ'ed in RAI 2.3.4.1-2 resolved.,

RAI 2.3.4.1-3 ' ' ' '

License renewal boundary drawings D-170114L and D-200007L show a component

represented by a dashed line symbol. However, the drawing D-175016 Units 1 and 2 standard

P&ID legend does not define this particular'dashed line.' The staff requested that the applicant

identify the components represented by this'dashed line and explain how the applicant -

considered them in the scoping and screening process.

Anmlicant's Response and Staff's'Evaluation

By letter dated April 22, 2004, the applicant responded that the dashed lines addressed in the -

RAI represent piping by others. The applicant further explained that the symbol used was not

an exact match with the symbol for piping b'y others shown in the drawing legend because of

variations in symbolism between different vendors.

In response to the staff's request about how it considered the components represented by the

dashed line in the scoping and screening process,'th'e applicant stated that it considered the

piping in the scoping and screening process' using the methodology described in LRA Section

2.1 and excluded it from the scope of license renhewal.

Based on is review, the staff finds the applicant's response to RAI 2.3.4.1-3 acceptable

because the applicant identified the components represented by the dashed line and explained

that it considered these components in the scoping and screening process using the

methodology described in LRA Se6tion 2.i. 'Therefore, the staff considers RAI 2.3.4.1-3

resolved.

2.3.4.1.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal.

The staff found no omnissions. In addition, the6 taff p6rformed an'independent assessment to

determine whether-the applicant identified all components that should be'subject to an AMR.

The staff found no omissions. On the basis of its'review, the staff concludes that the applicant

has adequately identified the components of the'rfiain steam LRA system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

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identified the components of the main steam LRA system that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.4.2 Feedwater System

The feedwater LRA system comprises the condensate and feedwater system, feedwater control

system, chemical injection system, and portions of the AFW system.

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 feedwater LRA system. The

condensate and feedwater system returns condensed steam from the main-condenser through

the feedwater heaters to the steam generators. The feedwater control system modulates the

feedwater flow rate to control levels in the steam generators during normal and transient

conditions and isolates feedwater system flow when required during abnormal conditions. The

main feedwater control valves and main feedwater bypass control valves are part of the

feedwater control system.

The chemical injection system allows for the addition of chemicals to the feedwater fluid to

minimize corrosion in the feedwater system and in the steam generators.

The portion of the AFW system that interfaces with the main feedwater lines up to and including

the first isolation valve forms an integral part of the normal feedwater pressure boundary and

has been included as part of the feedwater LRA system. The remainder of the system

comprises the AFW LRA system.

The condensate and feedwater system from the feedwater isolation valves to the steam

generators is safety related and an integral part of the AFW flowpath pressure boundary for

providing emergency feedwater to the steam generators. This portion of the system and the

portions of the chemical injection and AFW systems that interface with the main feedwater lines

up to the first isolation valves provide containment isolation and steam generator isolation

pressure boundary functions, as well as support to the AFW flowpath. Rapid and redundant

isolation of the main feedwater lines to prevent sustained high flow is accomplished via tripping

the main feedwater pumps and automatic closure of the main feedwater control valves and

main feedwater bypass control valves, in addition to closure of the feedwater isolation valves.

The LRA addresses level sensors, provided in the main steam valve room to detect flooding

indicative of a line rupture and assigned to the condensate and feedwater system, separately

as part of the HELB detection LRA system boundary.

In Table 2.2-1 d of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the feedwater system components that are within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* . environmental qualification (10 CFR 54.4(a) (3))

* anticipated transient without scram (10 CFR 54.4(a)(3))

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In Table 2.3.4.2 of the LRA, the applicant listed the feedwater system component types that are

within the scope of license renewal and subject to an AMR, including closure bolting, piping,

and valve bodies.

In its response to RAI 2.1 1 (discussed in Section 2.1 of this SER), the applicant changed the

methodology'used for scoping of unattached,' non-safety-related piping for the feedwater

system in accordance with 10 CFR 54.4(a)(2). By letter dated June 4, 2004, the applicant

submitted the supplemental information associated with the determination of SSCs within the

scope of license renewal, in accordance with the requirements of 10 CFR 54.4(a)(2), as a result

of the changed scoping methodology (see Enclosure 2, "Joseph M. Farley Nuclear Plant Units 1

and 2, Application for License Renewal, Supplemental Information Related to .10 CFR

54.4(a)(2)").'',..

The methodology change resulted in an expansion'of the mechanical SSCs within the scope of

license renewal. In its supplemental information related to 10 CFR 54.4(a)(2), the applicant

listed the impact of changes in the 10 CFR 54.4(a)(2) scoping methodology on the LRA results

of the in-scope components for the feedwater system:. rIn Enclosure 2 of the letter, the applicant

stated that changes in the 10 CFR 54.4(a)(2) scipin'g methodology affect a portion of the

chemical addition system (addressed as part of the feedwater LRA system in the application).

The portion of the chemical addition systemithat is located iri the auxiliary building on the 100'

elevation is of concern. The system is normally unused (it is occasionally used for batch

processing of wet lay-up chemicals) and unpressurized. When used, the system is operated

locally such that any leak in the area containing the safety-related SSCs would be immediately

detected and the operation stopped.' '

A through-wall failure in the system cornmponents on the'discharge side of the system pumps

could expose vulnerable'safety-related SSCs in the space to the treated water of the system.,

Therefore, the applicant indicated the discharge-side lines in the scope of the license renewal

and evaluated them for aging effects that require" management.

The chemical addition system is supplied from the CST, and the supply line runs in the 'same

room as safety-related components. Since the supply-side of the system is left unpressurized

(isolated), a spray from a failure in these components is not postulated. None of the

supply-side components are routed above non-safety-related SSCs 'that are 'vulnerable to a

leak. Room drainage is available; therefore, leakage would not lead to a flooding event that

would compromise the safety-relate'd corm'ponents inrthe area." Similarly, leakage from the

chemical addition tanks,(100 gallon capacity) or skid components (on the supply side of the

pumps) would not cause a flood in the lower equipment room or connected rooms that would

lead to a failure of a SR component. ' ,

Because of the expanded scope, the appiciant'statbd that it included the chemical addition

pump casings and the pump discharge-side line within the scope of license renewal and

evaluated them for aging effects that required 'rmiah agement.: Tables 2.3.4.2 and 3.4.2-2 of the

LRA should include the componient typre 'Iuuipc'asings."

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section'2.3.4.2 and FNP FSAR Sections'10.47 and 10.3.5. The staff

conducted its review, using the evaluation'm' riethodology described in Section 2.3 of this SER; in

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I'

accordance with the guidance described in Section 2.3 of NUREG-1800.

In its evaluation, the staff used the scoping process described in Section 2.3 of this SER, to

review the FSAR to determine if the applicant identified all system functions in the LRA as an

intended function of the feedwater system, in accordance with the requirements of

10 CFR 54.4(a). The staff did not identify any omissions. The staff then reviewed the FSAR, in

accordance with the screening process described in Section 2.3 of this SER, to verify that the

applicant did not omit any passive and long-lived components from an AMR, in accordance with

10 CFR 54.21 (a)(1).

The staff found that the applicant included those portions of the feedwater system that meet the

scoping requirements of 10 CFR 54.4 within the scope of license renewal, and identified them

as such in LRA Section 2.3.4.2, and included the feedwater system components that are

subject to an AMR in accordance with 10 CFR 54.21 (a)(1) in LRA Table 2.3.4.2. The staff did

not identify any omissions.

The staff finds the supplemental information related to 10 CFR 54.4(a)(2) in the June 4, 2004,

Enclosure 2 (discussed in Section 2.2.3) to be acceptable, on the basis that it adequately

identified all feedwater system's non-safety-related SSCs that are added to the scope of license

renewal as a result of the changed 10 CFR 54.4(a)(2) scoping methodology.

2.3.4.2.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within th6 scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent assessment to

determine whether the applicant identified all components that should be subject to an AMR.

The staff found no omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the feedwater LRA system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the feedwater system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.4.3 Steam Generator Blowdown System

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 steam generator blowdown (SGBD)

system. This system provides a continuous blowdown of water from the lower portion of each

steam generator tube bundle to remove solids and chemical contaminants that accumulate in

the steam generators during normal operations. Removing these impurities helps maintain

proper water chemistry and minimizes corrosion on the secondary side of the steam

generators. The blowdown from each steam generator flows under pressure into a common

manifold and then to a heat exchanger, where the temperature is reduced before processing

the effluent.

Portions of the SGBD system are brought into scope for containment isolation (where the

SGBD piping penetrates containment) and as a result of the potential for spatial interaction with

safety-related SSCs. The SGBD lines from the steam generators to the processing system are

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high-energy lines. High-energy line break room pressure sensors isolate blowdown from the

steam generators if a rupture is detected. The applicant addressed the compartment/room

pressure sensors separately as part of the HELB detection LRA system boundary.

In Table 2.2-1 d of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the SGBD'system components that are within the'scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* anticipated transient without scram (10 CFR 54.4(a)(3))

In Table 2.3.4.3 of the LRA, the applicant listed the SGBD system component types that are

within the scope of license renewal and subject to an AMR, including closure bolting, piping,

and valve bodies.

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3 and FNP FSAR Section 10.4.9. The staff conducted its

review, using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff used the scopirig p-rocess described in Section 2.3 of this SER to

review the FSAR to determine if the applicant identified all system functions in the LRA as an

intended function of the SGBD system, in accordance with the requirements of 10 CFR 54.4(a).

The staff did not identify any omissions. The staff then reviewed the FSAR, in accordance with

the screening process described in Section 2.3 of this'SER, to verify the applicant had not

omitted passive and long-lived components'from an AMR, in accordance with

10 CFR 54.21 (a)(1). -

The staff's review of LRA Section 2.3.4.3 idehtified~ari'area in which it nedded additional -

information to complete the evaluation of the applica'nt's scoping and screening results.

Therefore, by letter dated March 23, 2004,the 'staff issued an RAI 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 describes the staff's RAt and the applicant's response,

dated April 22, 2004.

RAI 2.3.4.3-1

License renewal boundary drawing D-175071 Lfor the"SGBD shows that the only portion of the

SGBD systetn that is within the scope of licbnse renewal in accordance with 10 CFR 54.4(a)(1)

extends from the' steam generators to the 6bntainment isolation valves. According to' LRA :

Section'2.3.4.3, 'other portiors of the system are brought into scope under 10 'CFR 54.4(a)(2).

However, the LRA does not identify the specific portioni and their components. '

Section 10.4.8.2 of the FNP FSAR states that in the event that radiation monitors in the system

detect a high level of activity in the blowdown fluid, a control valve downstream of the SGBD

heat exchanger will trip closed, providing automatic isolation of the system. However,'the -

FSAR does not identify the specific location of this blowdown isolation valve. Because this

valve performs an isolation function, and all cornponerits upstream of it (to the containment

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isolation valves) perform the intended function of pressure boundary, the staff concludes that

these components should be within the scope of license renewal and subject to an AMR.

The staff requested that the applicant provide the location of the above-mentioned blowdown

isolation valve and justify the exclusion of this valve and all components upstream (to the

containment isolation valves) from the scope of license renewal and from an AMR, in

accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively.

Applicant's Response and Staff's Evaluation

By letter dated April 22, 2004, the applicant responded that three different types of valves can

automatically isolate the SGBD system-(1) the containment isolation valves which close on a

containment isolation signal, (2) a set of two valves located upstream of the containment

isolation valves (already in scope under 10 CFR 54.4(a)(1)) which close on a high roompressure signal caused by an HELB, (3) and a third valve which closes on a high radiation

signal and functions to minimize releases during normal plant operations to meet 1O CFR Part

20 ALARA requirements. This third valve and the components upstream of it (to the

containment isolation valves) are excluded from the scope of license renewal under

10 CFR 54.4(a)(1) because the portion of the SGBD system downstream of the containment

isolation valves is not safety related, and this valve is utilized only during normal operations.

However, the applicant added that the portion of the SGBD system between the containment

isolation valves and the SGBD heat exchanger is within the scope of license renewal under

10 CFR 54.4(a)(2) because of potential spatial interactions with safety-related components;

therefore, it is not highlighted on the license renewal boundary drawings.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.3-1 acceptable

because it adequately explains the various isolation functions associated with the SGBD system

and explains the basis for (1) excluding the portion of the system located downstream of the

containment isolation valves (up to the SGBD heat exchanger) from the scope of license

renewal under 10 CFR 54.4(a)(1), and (2) including the portion of the SGBD system between

the containment isolation valves and the SGBD heat exchanger within the scope of license

renewal under 10 CFR 54.4(a)(2). Therefore, the staff considers the concerns described in RAI

2.3.4.3-1 resolved.

2.3.4.3.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal.

The staff found no omissions. In addition, the staff performed an independent assessment to

determine whether the applicant identified all components that should be subject to an AMR.

The staff found no omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the SGBD system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the SGBD system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.4.4 Auxiliary Feedwater System

The systems that comprise the auxiliary feedwater (AFW) LRA system include the AFW system

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and the condensate storage tank (CST) portion of the condensate and demineralized water

transfer and storage system. -

2.3.4.4.1 Sum ma'ry of Technical Information in'the Application

In Section 2.3.4.4 of the LRA, the'applicant described the AFW LRA system. The AFW system

is designed to supply feedwater to the6 steam generators during startup, cooldown, and

emergency conditions. Two motor-driven and one turbine-driven AFW pumps ensure the

availability of the required feedwater flow to the steam generators. During normal operations,

the system is in a standby mode, with controls selected for automatic operation.

The condensate and demineralized water transfer and storage system stores water in the CST.--

to provide makeup' and 'surge capacity to compensate for changes in the turbine plant systems

inventory and to provide a supply of water for the AFW system for shutdown decay heat ;

removal. -The lower portion of the tank is designed to ensure that 150,000 gallons remain in the

tank for emergency use. The applicant addressed the demineralized water transfer and

st6rage portion of the system as part of the demineralized water LRA system.

The AFW system is relied upon as the source of feedwater supply to the steam generators to

maintain a secondary heat sink for DBE mitigation, and therefore the SCs that perform this.

function are safety related. The CST provides the feedwater source for the AFW system for

normal and DBE mitigation. -Th6e service water system can also supply the AFW system if

needed. However, this system is not credited for mitigation of any DBE.

In Table 2.2-1d of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the AFW LRA system components that are within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* - dnon-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

* anticipated transient without scram (10 CFR 54.4(a)(3))

In Table 2.3.4.4 of the LRA, the applicant listed the AFW LRA system component types that are

within the scope of license renewal and subject to an AMR, including closure bolting, filters

(casing), flow orifice/eleinmnt, 'oil cooler (shell), oil cooler (channel head), oil cooler, (tubesheet),

oil cooler (tubes)- piping, pump casings, CSTs, and valve bodies..

2.3.4.4.2 Staff Evaluation - --

The staff reviewed LRA Section 2.3.4.4 and FNP FSAR Sections 6.5 and 9.2.6. The staff

conducted its review, using the evaluation methodology described in Section 2.3 of this SER, in

accordance with the guidance described in Section 2.3 of NUREG-1800. i - . ai . . - .i -u-- :.---

In its evaluation, the staff used the scoping process described in Section 2.3 of this SER to

review the FSAR to determine if the applicant identified all system functions in the LRA as an

intended function of the AFW system, in accordance .with the requirements of 10 CFR 54.4(a).

The staff did not identify any omissions. The staff then reviewed the FSAR, in accordance with

the screening process described in Section 2.3 of this SER, to verify that the applicant did not

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omit passive and long-lived components from an AMR, in accordance with 10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.4.4 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 23, 2004, the staff issued RAls 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 describes the staff's RAls and the applicant's responses,

dated April 7, 2004.

RAI 2.3.4.4-1

Section 6.5.2.2.2 of the FNP FSAR states that a forced-feed lube oil system driven from the

turbine shaft lubricates the AFW turbine bearings. Several of the components listed in LRA.

Table 2.3.4.4 compose part of the turbine lube oil subsystem. Since the AFW pump turbine

drive must be operable for the AFW system to perform its intended function, the staff considers

the turbine lube oil subsystem to be within the scope of license renewal. However, license

renewal boundary drawings D-1 75007L, D-205007L, D-1 75033L, and D-205033L do not show

the turbine lube oil subsystem and its components.

The staff requested that the applicant confirm that all components of the turbine lube oil

subsystem (AFW system) are within the scope of license renewal and subject to an AMR, in

accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1), respectively, or

provide drawings which show the turbine lube oil subsystem and all of its components and

identify those components considered to be within the scope of license renewal and subject to

an AMR.

Applicant's Response and Staff's Evaluation

By letter dated April 7, 2004, the applicant responded by providing a schematic diagram of the

turbine lube oil subsystem showing all of its components. The diagram identified additional

components which are subject to an AMR and were not previously included in LRA Table

2.3.4.4; the applicant revised the table accordingly. These components include sight glasses

and tanks (auxiliary oil reservoir). The applicant also made corresponding revisions to LRA

Table 3.4.2-4.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-1 acceptable

because, with the addition of the above-mentioned components to LRA Table 2.3.4.4, it

identifies all components within the scope of license renewal, in accordance with 10 CFR 54.4,

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

the staff considers RAI 2.3.4.4-1 resolved.

RAI 2.0-2F (D-RAI 2.3.4.4-2)

The license renewal boundary drawing D-175016 Unit 1 and Unit 2 standard P&ID legend, and

boundary drawings D-1 75007L and D-205007L show the symbol for startup strainer temporary

within the scope of license renewal. Strainers are passive, long-lived components and are not,

listed in LRA Table 2.3.4.4 as component types subject to an AMR.

The staff requested that the applicant justify the exclusion of the startup strainer temporary from

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an AMR, in accordance with th6 re'quirements of ' 0 CFR 54.21 (a)(1).-

Applicant's Response and Staff's Evaluation- ':

By letter dated April 7, 2004, the applicant responded that these strainers were removed after

initial system startup and are no longer in use6.-'Pipe spool pieces have replaced the strainers

and are included in the component type Upipijig" in LRA Table 2.3.4.4.

Based on its review, the staff finds the applicant's response to RAI 2.0-2F acceptable because

it adequately justifies the exclusion of the startup strainer temporary from an AMR, in

accordance with the requirements of '10 CFR 54.21 (a)(1). Therefore, the staff considers its

concern described i "RAI 2.0-2F resolved.

As part of its review of the implementationof the 'applicant's methodology, as described in the

LRA Section 2.1, the NRC inspectors completed a license renewal scoping and screening.-`.

inspection on May 14, 2004, which'is documrented in Inspection Report 50-348/2004-007,

50-364/2004-007, dated June 22, 2004. -The inspection consisted of a selected examination of

procedures and representative recbrds and interviews with personnel regarding the process of

scoping and screening plant components to select components subject to an AMR.

Additionally, the NRC inspectors performed avwalkdown of selected areas of the plant

containing SSCs that are considered to be Within the-scope of license renewal because they

meet the 10 CFR 54.4(a)(2) 'requirement. -For'a sample of plant systems, specifically those that

the NRC reviewers identified, the NRC inspectors performed visual examination of accessible

portions'of the systems to observe any effects of component aging.

The inspectors concluded that the applicant had successfully performed scoping and screening

and identified the SCs subject to aging management, in accordance with the methodology

described in the LRA and the Rule, with the following exception.

The inspectors noted that boundary drawings'were'inconsistent on various drawings in

depicting the atmospheric vents for the refueling' water storage, condensate storage, and the

RMWS tanks as in or out of the scope of lic'ense renewal.

By letter dated July 9, 2004, the applicant provided supplemental information on the

atmospheric vents on the RWSTs, CSTs, and RMWS tanks. In this supplement, the applicant

agreed to include these veents in the scope''6f liceinise renewal. The applicant stated that these

ventlines are considered as'an integral subpart of the tanks'and, consequently,-are lumped into

the existing "tank" component type. Therefore, thiecomponent types in the AMR tables in the

corresponding LRA scoping sections are unaffected. However, the applicant stated that the

AMR summary tables should have included additional material-environment combinations for

the tanks as a result of bringing' the tank vents into scope and provided the additions to the

corresponding AMR summary tables. "

2.3.4.4.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary-drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal. In

addition, the staff performed'an independent assessment to determine whether the applicant

omitted any components that should be subject to an AMR. The staff identified no omissions.

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On the basis of its review, the staff concludes that the applicant has adequately identified the

components of the AFW system that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the components of the AFW

system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.5 Auxiliary Steam and Condensate Recovery System

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 auxiliary steam and condensate

recovery LRA system. This system supplies steam for various heating and system loads in the

auxiliary and turbine buildings and provides a method of collecting and pumping the condensate

from those steam loads back to the turbine building. Steam is drawn from the main steam

system. The original plant design included an auxiliary steam generator to supply steam when

neither unit could supply steam, but this generator is no longer operational. In the auxiliary

building, steam is supplied for. loads such as the recycle evaporator and the plant hot water

heat exchanger. Condensate from the auxiliary building is processed via the turbine building

drains. The auxiliary steam and condensate recovery system is not safety related.

The auxiliary steam and condensate recovery LRA system is within the scope of license

renewal, in accordance with 10 CFR 54.4(a)(2), for spatial interaction with safety-related SSCs

and because portions of the system comprise high-energy lines and components.

In Table 2.2-1 d of the LRA, the applicant identified the following 10 CFR 54.4(a) criteria it used

to determine the auxiliary steam and condensate recovery system components that are within

the scope of license renewal:

* nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

In Table 2.3.4.5 of the LRA, the applicant listed the auxiliary steam and condensate system

component types that are within the scope of license renewal and subject to an AMR, including

valve bodies, piping, pump castings, strainers (shell), closure bolting, and tanks.

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 and FNP FSAR Section 10.2.2. The staff conducted its

review, using the evaluation methodology described in Section 2.3 of this SER, in accordance

with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff used the scoping process described in Section 2.3 of this SER to -

review the FSAR to determine if the applicant identified all system functions in the LRA as an

intended function of the auxiliary and condensate recovery system, in accordance with the

requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff then

reviewed the FSAR, in accordance with the screening process described in Section 2.3 of this

SER, to verify that the applicant did not omit passive and long-lived components from an AMR,

in accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.5 identified areas in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

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Therefore, by letter dated Martch 23, 2004,1th1 siaff issued RAI 2.4.5-2 and, by letter dated

April 1,'2004, the staff issued RAI 2.4.5-4 t6 determine whether thd'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 describes the staff's RAls and the applicant's responses, dated April 7, 2004 and April

29,2004.

RAI 2.0-2G (D-RAI 2.3.4.5-2)

The FNP FSAR uses the designation "auxiliary steam supply system" and states that Units 1

and 2 share this system. However, the FSAR makes no reference to the "auxiliary steam and

condensate recovery system," a designation used in LRA Section 2.3.4.5.

The staff 'requested that the applicant clarify whether'the two 'different designations represent

the same system. If not, the staff asked the'applicant to describe how the'systems differ.-

Additionally, the 'staff requested the applicant'to provide license renewal boundary drawings

which show the shared components and identify those components considered to be within the

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

Applicant's Response and Staff's Evaluation'

By letter dated April 7, 2004, the applicant responded that the "auxiliary steam supply system"

listed in FSAR Section'1.2.2 is the same as'the uauxiliary steam and condensate recovery

system" described in LRA Section 2.3.4.5. However, the "auxiliary steam supply system" listed

in the FNP FSAR is not the- same as the "auxiliary steam system" described in LRA Section -

2.3.4.1. The latter'system consists of the supply lines from the main steamlines to the AFW

pump turbine and is included as part of the'main steam system. License renewal boundary

drawings D-175033L (Unit 1) and D-205033L' (Unit 2) show these lines. -

Additionally, the applicant identified the corponents'of the auxiliary steam and condensate

recovery system shared by Units 1 and 2 as the auxiliary steam generator, steam supply piping

connecting the auxiliary steam generator to the Unit 1 auxiliary steam distribution piping, and

condensate return piping from each unit to the auxiliary steam generator. The applicant also

stated that the auxiliary steam generator is no'longe'r operational so that the shared

components perform no license renewal intended function."Therefore, all shared components

located in the turbine building,' are excluded fromrthe'scope of license renewal because they do

not perform any intended function,'as described in the'requirements of 10 CFR 54.4(a)..

Based on its review, the staff finds the applica3nt's response' to' RAI 2.0-2G acceptable because

it satisfactorily explains the differences in'system'nomenclature used in the'LRA and the FSAR

and clarifies that the auxiliary feed and condensate recovery system components shared by

Units 1 and 2 do not perform-any license renewal intended function;-as such, they are excluded

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

Therefore, the staff considers the concerns described in RAI 2.0-2G resolved.

RAI 2.3.4.5-4 ; 4 .

Table 2.3.4.5 of the LRA lists "strainers (shell)" as a'componen't type subject to an AMR.-

However, the license renewal boundary drawings D-175033L'and D-205033L for the auxiliary

steam and condensate system do not show any' strainers (shell) within the scope of license

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if

renewal. Therefore, the staff is concerned that other drawings which the LRA does not

reference may include components of the system that should be included within the scope of

license renewal.

The staff requested that the applicant provide drawings that identify the strainers in the auxiliary

steam and condensate system that are within the scope of license renewal and subject to an

AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1),

respectively.

Applicant's Response and Staff's Evaluation

By letter dated April 29, 2004, the applicant responded that the non-safety-related auxiliary

steam and condensate recovery system is solely within the scope of license renewal under10 CFR 54.4(a)(2) for spatial interaction consideration with safety-related SSCs, including highenergy piping considerations, as stated in LRA Section 2.3.4.5. The "strainers (shell)"

component type listed in LRA Table 2.3.4.5 represents strainers, which are located between the

auxiliary steam condensate tank and the auxiliary steam condensate pumps. The strainers

have a potential spatial interaction with nearby safety-related electrical components in Rooms

189 and 2189, and license renewal boundary drawing D-506447L identifies the spatial

interaction concern in these rooms for this system.

As part of its review of the implementation of the applicant's methodology, as described in the

LRA Section 2.1, the NRC inspectors completed a license renewal scoping and screening

inspection on May 14, 2004. The inspection consisted of a selected examination of procedures

and representative records and interviews with personnel regarding the process of scoping and

screening plant components to select components subject to an AMR. Additionally, the NRC

inspectors performed a walkdown of selected areas of the plant containing SSCs that are

considered to be within the scope of license renewal because they meet the 10 CFR 54.4(a)(2)

requirement. For a sample of plant systems, specifically those that the NRC reviewers

identified, the NRC inspectors performed visual inspection of accessible portions of the systems

to observe any effects of component aging.

As part of its consideration of the applicant's response to RAI 2.3.4.5-4, the staff could not

determine which specific components were within the scope of license renewal, according to

10 CFR 54.4(a)(2), and subject to an AMR. Therefore, the staff requested that the inspection

team verify that LRA Table 2.3.4.5 includes the component types and intended functions for the

non-safety-related components in the listed rooms. As documented in Inspection Report

50-348/2004-007, 50-364/2004-007, dated June 22, 2004, the inspectors reviewed the system

scoping and screening documents, design-basis information, applicable FSAR sections, and

boundary drawings and concluded that the applicant's identification of in-scope components, in

accordance with the requirements of 10 CFR 54.4(a)(2), was consistent with the application of

the license renewal rule.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.5-4 acceptable

because it adequately explains that the strainers in the auxiliary steam and condensate

recovery system are within the scope of license renewal under 10 CFR 54.4(a)(2) for spatial

interaction consideration with safety-related SSCs. In addition, the NRC inspectors reviewed

the system scoping and screening system documents and concluded that the applicant's

identification of in-scope components, in accordance with the requirements of

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10 CFR 54.4(a)(2), was consistent viththe6aplidation of the license renewal rule. Therefore,

the staff considers the concerns described in RAi 2.3.4.5-4 resolved.

2.3.4.5.3 Conclusion

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that should be within the scope of license renewal.

The staff found no omissions. In' addition,-th~estaff 'performed an independent assessment to

determine whether the applicant identified all c6riomponents that should be subject to an AMR.

The staff found no omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the 'auxiliary steam'and condensate recovery'.

system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has adequately identified the components of the auxiliary steam and condensate

recovery system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.6 Turbine and Turbine Auxiliaries - -

The turbine and turbine auxiliaries LRA system' comprises the main turbine and certain 'auxiliary

equipment.

2.3.4.6.1 Sunmmary of Technical Informationin th'e Application' -

In Section 2.3.4.6'of the LRA, the applicant described the turbine and turbine auxiliaries'LRA

system. The main'stearn turbine, which draws stearm from the main steam system, drives the

main generator to produce the plant electrical output. The turbine control system,' which

includes the digital electrohydraulic (EH) control subsystem, is integral to the operation of the

turbine. The turbine auxiliaries include the moisture separator reheaters (MSRs), extraction

and reheat steam components, gland sealing steam comnponents, a'nd the turning gear for

rolling the turbine at very low speeds when'steam is'unavailable: The turbine lube oil system,

which includes the both the lubricating oil and auto-stop oil subsystems, is also included.

Four parallel flowpaths supply steam to'the high-pressure turbine, where each path is equipped

with a throttle valve and a governor valve. Steam exiting the high-pressure turbine'is passed

through the MSRs, where reheating and moisture removal takes place before the steam enters

the two low-pressure turbines via four parallel paths. Each of these paths is equipped with a:.

reheat stop valve and a reheat intercept valve.

The turbine control system positions the'steam valves controlling steamflow to the high- -

pressure'and low-pressure'turbines (i.e., high-pressure throttle'and governor valves, and reheat

stop and intercept valves).' The EH subsystem 'operates to' meet the fluid pressure demands for

positioning these'steanm valves. The turbine lube oil system provides pressurized oil to the !

auto-stop oil header, in addition to providing lubrication for the turbine. Dumping the auto-stop

oil header pressure or the EH fluid pressure to the actuators will close the steam valves

(tripping the turbine).' - - - i - - -

The non-safety-related SCs of the turbine'and turbinre auxiliaries that are required to trip the

turbine in response to-an ATWS event and in response to a turbine overspeed event are'

conservatively included in'the'sc6pe of license'renewal. The turbine overspeed trip reliability is

an input to the turbine missile probability analysis that demonstrates the-adequacy of the plant

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design. Therefore, the scope of license renewal conservatively includes the SCs that perform

this function, in accordance with 10 CFR 54.4(a)(2).

In Table 2.2-1 d of the LRA, the applicant identified the following 10 CR 54.4(a) criteria it used to

determine the turbine and turbine auxiliaries LRA system components that are within the scope

of license renewal:

* non-safety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* anticipated transient without scram (10 CFR 54.4(a)(3))

In LRA Section 2.3.4.6, the applicant stated that there are no mechanical components of the

turbine and turbine auxiliaries that are subject to an AMR.

2.3.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6 and FNP FSAR Sections 10.1, 10.2, 10.4.3 and 7.8.

The staff conducted its review, using the evaluation methodology described in Section 2.3 of

this SER, in accordance with the guidance described in Section 2.3 of NUREG-1 800.

In its evaluation, the staff used the scoping process described in Section 2.3 of this SER to

review the FSAR to determine if the applicant identified all system functions in the LRA as, an

intended function of the turbine and turbine auxiliaries, in accordance with the requirements of

10 CFR 54.4(a). The staff did not identify any omissions. The staff then reviewed the FSAR, in

accordance with the screening process described in Section 2.3 of this SER, to verify that the

applicant included all passive and long-lived components from an AMR, in accordance with

10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.4.6 identified an area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated April 1, 2004, the staff issued an RAI 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 describes the staff's RAI and the applicant's response,

dated April 29, 2004.

RAI 2.3.4.6-1

Section 2.3.4.6 of the LRA states that, in accordance with 10 CFR 54.4(a)(3), "The non-safetyrelated SCs of the turbine and turbine auxiliaries that are required to trip the turbine in response

to an ATWS event and in response to a turbine overspeed event are conservatively included

within the scope of license renewal for FNP." However, LRA Section 2.3.4.6 also states that no

mechanical components of the turbine and turbine auxiliaries are identified as subject to an

AMR.

Since LRA Section 2.3.4.6 does not provide or reference any license renewal boundary

drawings associated with the turbine and turbine auxiliaries, the staff could not confirm that the

turbine and turbine auxiliaries do not contain mechanical components subject to an AMR. To

complete its review, the staff requested that the applicant provide a description or license

renewal boundary drawing that identifies the components of the turbine and turbine auxiliaries

and that shows which SCs are considered to be within the scope of license renewal, in

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accordance with the requirements of 10 CFR154.4(a). The staf aiso requested that the

applicant justify the exclusion of the mechaniicai c6mponents of the turbine and turbine

auxiliaries from an AMR, in accordance with the requireents of 10 CFR 54.21 (a)(1).

Applicant's Response and Staff's Evaluation

By letter dated April 29, 2004, the applicant provided a detailed discussion of the turbine trip

functions associated with this system, supplemented with schematic diagrams. The applicant

stated that active comporients perform trip functions, and any failure of a passive component,'in

particularrthe loss of pr6ssure boundary, w6uld 'not revent the'system from performing its

intended function (turbine trip in response to a6nATWS event or turbine overspeed event): 'A

loss of pressure boundary in either the EH fluid subsystem or the auto-stop oil subsystem would

automatically initiate a turbine trip rather than prevent one. Since the passive components of -

the turbine trip system have no license renewal intended functions, the applicant concluded that

no mechanical components are subject to an AMR.

As part of its review of the implementation of the applicant methodology, as described in the

LRA Section 2.1,-the NRCfinspectors completed aiicense renewal scoping and screening

,inspection on May 14, 2004. The inspection consisted of a selected examination of procedures

and representative records and interviews'with personnel regarding the process of scoping and

screening plant components to select components subject to an AMR.- The NRC inspectors

also performed a walkdown of selected areas of the'plant containing SSCs that are considered

to be within the scope of license renewal because they meet thel 0 CFR 54.4(a)(2) requirement.

For a sample of plant systems, specifically those that the NRC reviewers identified, the NRC

inspectors performed a visual examination of accessible portions of the systems to observe any

effects of component aging.

As part of its consideration of the applicant's response to RAI 2.3.4.6-1, the staff requested that

the inspection team confirm that the turbine and turbine auxiliaries components required for the

license renewal function included no passive components requiring an AMR. As documented in

Inspection Report 50-348/2004-007, 50-364/2004-007, dated June 22,- 2004, the inspectors' '

reviewed the applicant's RAI response and the schematics for the EH systems and the turbine

lube oil system and reviewed the accessible components in the field. The inspectors identified

no passive components subjected to license'renewal scope.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.6-1 acceptable,

because it satisfactorily demoristrates that only active components perforrh the turbine trip

function and that the passive components hav e'no license renewal intended functions, and the

inspection report verifies that no mechanical component of the turbine trip system is subject to

an AMR, in accordance with the requirements'of 10 CFR 54.21 (a)(1); Therefore, the staff

considers RAI 2.3.4.6-1 resolved.

2.3.4.6.3 Conclusion -

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether the applicant identified all SSCs that'sh6uld be within the scope of license renewal.

The staff found no omissions. -In addition; the staff performed an'independent assessment to

determine whether the applicant identified all components that should be subject to an AMR.

The staff found no omissions. On the basis of its review, the staff concludes that the applicant

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has adequately. identified the components of the turbine and turbine auxiliaries system that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the components of the turbine and turbine auxiliaries system that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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

Supports

This SER section documents the staff's review of the results of the applicant's scoping and

screening results for containments, structures, and component supports. This section reviews

the following structures and structural components:

* containment structure

* other structures

* component supports

In accordance with the requirements of 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 omitted no structures and structural components that meet

the scoping criteria and are subject to an AMR.

Staff Evaluation Methodology

The staff performed its evaluation of the information provided in the LRA in the same manner

for all SCs. The review determined if the applicant identified all the components and supporting

structures for a specific containment, structure, or containment support that appeared 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-live, passive components were subject to an AMR in accordance with

10 CFR 54.21 (a)(1).

Scopina. To perform its evaluation, the staff reviewed the applicable LRA section and

associated component drawings, focusing on components that the applicant had not identified

as within the scope of renewal. The staff reviewed relevant licensing basis documents,

including the FSAR, for each structure or structural component 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 applicant specified all intended functions delineated under 10 CFR 54.4(a) in the LRA. If it

identified omissions, the staff requested additional information to resolve the discrepancy.

Screening. Once the staff completed its review of the scoping results, the staff evaluated the

applicant's screening results. For those SCs with intended functions, the staff sought to

determine 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 that did not meet either of these criteria,

the staff sought to confirm that these structures and structural components were subject to an

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AMR, as required by 10 CFR 54.21(a)(1). IfWit identified discrepancies, the staff requested

additional information to resolve them.

2.4.0 Staff Evaluation

According to 10 CFR 54.21 (a)(1), the applicant must identify and list SCs subject to an AMR.

These are passive, long-lived SCs that are within the scope of license renewal. To verify that

the applicant has properly implemented its methodology,'the staff focuses its review on the

implementation results. Such a focus allows the staff to confirm that the applicant omitted no

structural components that are subject to an AMR. If the review identifies no omission, the staff

has the basis to find that the applicant identified the structural components that are subject to

an AMR.

This SER section addresses the applicant's scoping and screening results for structures. Table

2.2-1 e identified the following structures as within the scope of license renewal:

* containment structure (LRA Section 224.'i) '

* auxiliary building (LRA Section 2.4.2.1)

* diesel generator building (LRA Section 2.4.2.2)

* turbine building (LRA Section 2.4.2.3)

* utility/piping tunnels (LRA Section 2.4.2.4)

water control structures (LRA Section 2.4.2.5) -

* ''steel tank structures (foundations and retaining walls) (LRA Section 2.4.2.6)

yard structures (LRA Section 2.4.2.7)

component supports (LRA Section 2.4.3)

Table 2.2-1 h of the LRA identifies structures that are not within the scope of license renewal.

The staff's review of LRA Table 2.2-1 h identified several areas in which it needed additional

information to complete the evaluation of the applicant's scoping results.' Therefore, by letter

dated February 13, 2004, the staff issued RAI 2.4-1 to determine whether the applicant properly

applied the scoping criteria of 10 CFR 54.4(a). The following describes the staff's RAI:

LRA Table 2.2-1 h identifies'structures that are not within the scope of license renewal.

It is not obvious to the staff that all of the listed structures serve no intended function.

The applicant is requested to provide its technical basis for this determination for the

following structures: circulating water structures and cooling towers; containment

-equipment hatch access enclosure; river water intake structure; meteorological &

microwave structures and equipment; and yard drainage system. Also verify that

seismic 11/I considerations are not applicable to any of the structures not in the scope of

license renewal (e.g., containrment equipment hatch access enclosure).

In addition, while the staff acknowledges that the tendon access gallery does n6t serve an

intended function in the strictest interpretation of the license renewal rule, significant industry

operating experience relates to flooding and corrosive environments in the tendon access

gallery that have contributed to degradation of the tendon anchorage 'componr6his and'

surrounding concrete. Management of the condition of the tendon access'gallery is a

preventive step to minimize aging effects for the prestressing system. The staff asked the

applicant to submit its plant-specific'operating/aging experience related to (1 ) flooding and

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corrosive environments in the tendon access gallery, and (2) degradation of the prestressing

system components (both steel and concrete) in the tendon access gallery, and, based on the

FNP-specific tendon gallery operating/aging experience, to discuss FNP's basis for excluding

the tendon gallery structure from an AMR, pursuant to 10 CFR 54.4(a)(2).

In its response to RAI 2.4-1, dated March 12, 2004, the applicant stated the following:

SNC has verified for the structures listed in Table 2.2-1 h 'Systems and Structures Not Within the Scope of

License Renewal-Structures," that seismic 11/I considerations are not applicable.

The staff requested the technical basis for determining the following structures are not in the

scope of license renewal: circulating water structures and cooling towers, containment

equipment hatch access enclosure, river water intake structure, meteorological and microwave

structures and equipment, and yard drainage system. These structures do not house

equipment relied upon in the licensing basis to perform safe shutdown, mitigate accidents, or

address any of the regulated events in the scope of the Rule. The structures cannot fail in a

way that adversely affects a safety-related function or the performance of safety-related

equipment. Therefore, these structures do not satisfy the criteria as defined in 10 CFR

54.4(a)(1-3) and are not within the scope of license renewal. The applicant provided the

following discussion for each structure:

Circulating Water Structures and Cooling Towers: The circulating water systems and structures, including

the cooling towers, provide cooling water to the tube-side of the main condensers for removal of waste heat

from the power cycle (including maintaining condenser vacuum in support of efficient turbine operation).

During a normal plant shutdown heat is rejected to the main condenser via the non safety-related main

steam dump valves, however this method is not credited for safe shutdown. The main steam safety valves

and main steam atmospheric relief valves, which discharge directly to the atmosphere, provide the safetyrelated means for decay heat removal to maintain hot shutdown. The circulating water structures include

the concrete basins under the cooling towers, concrete canals and tunnels that direct the water flow to and

from the condensers, and the circulating water pump structures. The cooling towers are not located near

any safety-related SSCs, and the circulating water structures cannot fail in any way that could interact with

a safety related structure.

Containment Equipment Hatch Access Enclosure: This non safety-related enclosure is a free-standing

sheet metal and steel frame structure that provides shelter over the equipment hatch access area from

inclement weather during outage activities. The enclosure is open on two sides to provide free access to

the Containment Equipment Hatch. The structure is of lightweight construction such that failure of the

structure (e.g., during a seismic event) will not impair the ability of the containment structure (including

equipment hatch) from performing its intended function.

River Water Intake Structure: Loss of the River Water Intake Structure is discussed in UFSAR Section

9.2.1.2.3.1 which states 'The station cooling water system is designed such that safe shutdown of the plant

is not dependent on the river water system as a cooling water source' and 'The storage pond alone serves

as the ultimate heat sink for the plant." The River Water Intake Structure is located remote from the plant's

safety-related structures (over 2000 feet from the Auxiliary Buildings and from the pond) and houses the

river water pumps and related equipment, none of which are required for safe shutdown (including in the

event of a fire) or to mitigate any accident. The portions of the River Water System within the scope of

License Renewal (i.e., the Service Water pond level instruments) described in LRA Section 2.3.3.5 are

located at the pond and not at or in proximity of the River Water Intake Structure.

Meteorological & Microwave Structures: Instruments for measuring meteorological parameters are

installed on a main and a backup tower located in a cleared area north of the plant site.

Microwave communication equipment is also installed on these towers. The towers and

equipment are non safety-related and do not pose any spatial interaction hazard to safety-related

SSCs based on the remote location. In addition, the intended functions of these SSCs do not

meet the 10 CFR 54.4(a) criteria for safety-related or regulated events. Some of the

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meteorological data is utilized for po'st-accident release assessment (R.G. 1.97 Category 3

variable) but is not safety-related (it d6es not mitigate; only assesses the consequences of an

accident). The microwave communication is connected to the intra plant telephone switchboard to

enable plant personnel to have dial service to other Alabama Power Company locations. The

-meteorological and microwave communication systems are not required in the licensing basis to

safely shutdown the plant or mitigate an accident.

Yard Drain-age System: The yard drainage system is a combined system of culverts and open ditches that

direct water (from rainfall) to natural drainage channels. The power block area, which is located on a small

plateau, utilizes the elevation difference and resultant topography to direct rainfall runoff away from the

facility. The yard drainage system assists in directing the rainfall runoff however the probable maximum

precipitation (PMP) evaluation assumed all of the buried storm drainage system was inoperative and the

PMP runoff was carried off on the ground (refer to FSAR section 2.4.10). The PMP evaluation. ;

demonstrated no flooding of a doorway or opening of a safety related building would occur from the runoff,

and therefore an operating storm drainage system is an added safeguard but is not relied upon in the

licensing basis for FNP. ;

Tendon Access Gallery

The following describe 'the'requested FNP plant-specific operating/aging experience related to.

the tendon access gallery: ' ' .,

flooding and corrosive environments in the tendon access gallery

A review of experience at FNP has identified ground waterintrusion into the containment

tendon acdess gallery. 'The ground water intrudes through construction joints between

the rionsafety-related tendon access gallery wall and the containment foundation. A

sump pump system is located in the tendon access gallery to pump out the water from

the gallery. -A few inches-of water accumulation has been identified at some areas in

the gallery'during inspections:

In summary, the FNP tendon access gallery is a high-humidity environment with water

accumulation controlled by the installed sump pump system.

degradation of prestressing components

The applicant has not observed any noticeable degradation of the prestressing system

components (both steel and concrete) in the tendon access gallery. Canned enclosures

filled with grease protect the prestressing system steel components that are exposed

(not in the concrete) to the tendon access gallery environment. The condition of these

cans is checked'a's part of the containment inspections.

The applicant has observed some' minor concrete leaching in the containment access

gallery. Leaching has been identified (along with ground water intrusion) at the int6iface

join't between the gallery and the'bottom of~the containment foundation., The leaching

material from th6 interface joint is considered insignificant in causing any deterioration-

'(the ground water at FNP is nonaggressive) and, therefore, does not result in any loss ,

of function.

As its basis for not including the tendon gallery structure within the AMR scope, pursuant to10 CFR 54.4(a)(2), SNC agrees with the following excerpt from NUREG-1800, which asserts

that the tendon access gallery does not perform an intended function, and that containment

. 1 '2-1 53
'1

inspections (i.e., IWL inspections) "provide reasonable assurance that the aging effects of the

tendon anchorages, including those in the gallery, will continue to perform their intended

functions":

The intended function of the post-tensioning system is to impose compressive forces on

the concrete containment structure to resist the internal pressure resulting from a DBA

with no loss of structural integrity. Although the tendon gallery is not relied on to

maintain containment integrity during DBEs, operating experience indicates that water

infiltration and high humidity in the tendon gallery can contribute to a significant aging

effect on the vertical tendon anchorages that could potentially result in loss of the ability

of the post-tensioning system to perform its intended function. However, containment

inspections provide reasonable assurance that the aging effects of the tendon

anchorages, including those in the gallery, will continue to perform their intended

functions. Because the tendon gallery itself does not perform an intended function, it is

not within the scope of license renewal.

Because of the conditions which exist in the tendon access gallery, the applicant has identified

this area for inspections during future outages to ensure that the gallery does not degrade to an

unacceptable structural condition. However, the applicant did not credit these inspections for

license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.4-1 acceptable because it

clearly describes the technical bases for determining that the circulating water structures and

cooling towers, containment equipment hatch access enclosure, river water intake structure,

meteorological and microwave structures and equipment, and yard drainage system are not

within the scope of license renewal. The applicant has also verified that seismic Category Il/I

considerations do not apply to any of the structures listed in LRA Table 2.2-1 h.

In addition, the applicant described its plant-specific operating/aging experience for the tendon

access gallery, including water intrusion through construction joints and the use of a sump

pump system in the gallery. To date, there has been no significant degradation of prestressing

system components. The applicant has identified the tendon access gallery for inspections

during future outages, to ensure that the gallery does not degrade to an unacceptable structural

condition; however, the applicant did not credit these inspections for license renewal. The

applicant quoted from NUREG-1 800, which states, "Because the tendon gallery itself does not

perform an intended function, it is not within the scope of license renewal."

Therefore, the staff considers its concern described in RAI 2.4-1 resolved.

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. The staff identified the need for

additional information about the applicant's scoping, screening, and AMR results for load

handling systems in order to complete its review. Therefore, by letter dated February 13, 2004,

the staff issued RAI 2.4-3 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

describes the staff's RAI:

Please clarify the complete scope of load handling systems in the Farley LR scope.

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LRA Section 2.3.3.4 'Overhead Heavy and Refueling Load Handling System" appears to

be limited to the major heavy lift and refueling-related systetnis. Are there any other load

'handling systems that serve-an intended function (e.g., seismic 11/l), and are included in

-the LR scope? If so, please provide a description of the other load handling systems inthe LR scope; define their intended-functions; identify whether they are in the

Mechanical Systems scope or Structures scope; and specify where the AMR is located

in the LRA. -

In its response to' RAI 2.4-3, dated March 12, 2004, the applicant stated the following:

, - .. . . . , I . .

Section 2.3.3.4 "Overhead Heavy and Refueling Load Handling System" is limited to the major heavy lift

and the refueling-related load handling systems. Included in the scope of licerise renewal for this LRA-'

system are the containment polar cranes, reactor cavity manipulator cranes, spent fuel bridge cranes, and

the spent fuel cask crane. The new fuel load handling systems are non safety-related and not in scope.

Based on the obse'rvations made during field walkdowns, failure of the new fuel load handling systems

could not prevent satisfactory accomplishment of any safety related function (spatial interaction).

Therefore, the new fuel load handling systems were not brought into the scope of license renewal as part of

the evaluation for the "Overhead Heavy and Refueling Load Handling System.'' -

All load handling systems (e.g., monorails, jib crane, new fuel load handling systems) used in Category I

structures were put in scope as part of the scoping of the associated structure in Section 2.4 of the LRA.

The 'spaces approach" used to scope the civil/structural components in these structures ensures all load

handling systems that serve an intended function (e.g., seismic 11/1) were included in the scope of license

renewal. - .: .' . . , t;

These components are in structural scope (Section 2.4 of the LRA) and their intended function Is Structural

Support. The Component Type 'Steel Components: All Structural Steel' for each building'covers the

passive long-lived components for these items (e.g., AMR Tables 3.5.2-2, 3.5.2-3, etc.). The Structural

Monitoring Program is credited for aging management of these passive loig-lived components. ''

Based on its review, thie staff finds 'the applicant's' response to RAI 2.4-3 acceptable because

the applicant has clearly described the load handling systems that are within the scope of

license renewal and has provided an acceptable technical basis for excluding the new fuel load

handling systems from the license renewal scope. Section 2.3.3.4, uOverhead Heavy and

Refueling Load Handling'System," of the LRA includes the containment polar cranes, reactor

cavity manipulator cranes, spent fuel bridge cranes, and the spent fuel cask crane under

mechanical systems scoping and screening. The applicant reviewed all other load handling

systems in Category I structures using a spaces approach. Section 2.4 of the LRA includes the

load handling'4 systdrns that serve an intended function (e.g., seismic Category Il/I) under

structures scoping and screening as structural c6mponents of the Category I structures in

which they are located. The components are 'all structural steel components, and the Structural

Monitoring Program is credited for their aging management; Therefore, the staff considers its

concern described in RAI 2.4-3 reiolved.

2.4.1 Containment Structures' - - - -

2.4.1.1 Summary of Technical Information in the Application

In Section 2.4.1 of the LRA, the applicant described the containment as a Class 1 structure that

completely encloses the reactor,'the RCS, the stearrigenerators,'and portions of the auxiliary

and ESF systems. The structure provides'protection for these features from external events

(e.g., tornado) and functions as a fission product barrier following an accident inside the .

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I,

containment. It ensures that an acceptable upper limit for leakage of radioactive materials to

the environment will not be exceeded even if gross failure of the RCS occurs. The structure

also provides biological shielding during normal operation and following a LOCA. In addition,

the containment structure includes components required for reactor refueling, including the

polar crane, refueling cavity, and portions of the fuel handling system.

The containment internal structures comprise concrete and steel components. The major

concrete internal components include the reactor cavity, primary shield wall, secondary shield

wall, refueling canal, and floor slabs. The major steel internal components include the RCS

supports, refueling canal liner, steel framing, miscellaneous platforms, pipe whip restraints, and

supports for cable trays, conduits, ventilation ducting, piping, and other components.

The applicant used a spaces approach for scoping and screening of the structures and

structural components located inside the containment structure. Support elements located in

the containment building, such as pipe supports, electrical raceways and their supports, HVAC

supports, and miscellaneous platforms, are in the scope of license renewal regardless of safety

designation or design classification.

The discussions of the major elements of the containment structure fall under the following

headings:

* structure and foundation

* steel liner plate

* penetrations

* containment internal structures

In Table 2.2-1 e of the LRA, the applicant identified the following criteria it used to determine the

SSCs for the containment structure that are within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

In Table 2.4.1 in the LRA, the applicant identified the containment structure components types

that are within the scope of license renewal and subject to an AMR, including concrete

elements (abovegrade dome, wall, ring girder, buttresses); concrete elements (belowgrade wall,

buttresses); concrete elements (foundation, subfoundation); concrete (internal structures); fuel

transfer tube; internal structures (steel liners); penetration sleeves and penetration bellows;

personnel airlock and equipment hatch; prestressing system (tendons, anchorage

components); seals, gaskets, and moisture barriers; steel components (refuel cavity and

transfer canal miscellaneous steel); steel elements (liner, liner anchors, integral attachments);

sump trash rack; and trisodium phosphate basket.

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 and the referenced FNP FSAR Sections 3.8, 6C,

6.2.3.4.1, and 9.1.4.2. The staff conducted its review in accordance with the guidance

described in Section 2.4 of NUREG-1800.

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In its evaluation, the staff revi6ewd the'FSAR to determine if the applicant identified all

structural or component functions'of the containment structure as an intended function, in

accordance with the requirements of 10 CFR 54.4(a). The staff did not identify any omissions.

The staff then evaluated that the passive, long-lived components were subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.1 identified one area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated March 2, 2004, the'staff issued RAI 2.4-7 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 describes the staff's RAI:

LRA Section 2.4.1 'Containment Structure" contains the following discussion related to

electrical penetrations through containment:

2.4.1.3 Penetrations

In general, a containment penetratio'n'consists of a'sleeve embedded in the-concrete

wall 6r floor and welded to the containmnbnt liner plate. -Loads on the penetration are -

transferred to the containment stricture The process pipe or cable-feed-through

assembly passes through the sleeve and is' seal welded to the sleeve via an appropriate

adapter. Additional detail is provided below.

Electrical Penetrations

Electrical penetrations consist of a sleeve that passes through the containment

boundary. The sleeve is welded to the containment liner plate. A cable feed-through

assembly is inserted in the sleeve and welded to the sleeve inside containment for

Conax and GE type penetrations. The'feed-through assembly is screwed to the clip

angle for a Westinghouse type penetration:

LRA Table 2.2-1f 'Systems and Structures within the Scope of License

Renewal-Electrical Components" specifically lists "(Electrical) Containment':-

Penetrations." However, LRA Table 2.5.1 'Electrical Component Types Subject to

Aging Management Review and their Intended Functions" does not specifically identify

the cable feed-through assembly.

LRA Table 2.4.1 "Containment Structure Component Types Subject to Aging

Management Review and their Intended Functions" does not identify any component

group that would obviously include the cable feed-thr6ughlassembly.-

From the information in the LRA,'the staff could not determine whether the applicant is treating

the cable feed-throughiassembly as a component of the containment structure or as an - -

ele6trical component. The staff asked th' applicant to clarify its treatment of the cable feedthrough assembly and to identify the location'of the AMR in the LRA. --

In its response to RAt 2.4-7; dated March 31, 2004, the"applicant stated the following:

For the Farley LRA, the cable feed-through assembly is treated as an electrical component with

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the electrical connection function addressed in the electrical scoping and screening evaluations.

However, the pressure-boundary and fission product barrier function of the assembly is included in

the civil/structural scoping and screening for the containment structure.

The last paragraph of the system description subsection of LRA Section 2.3.2.2, OContainment

Isolation System" outlines the division of responsibility for containment penetration assemblies

between the various disciplines (mechanical, electrical, and civil), however some minor

clarifications are needed. This paragraph should read as follows (changes are identified by bold

italics and strikeouts):

Note that the pressure boundary (meta portions of electrical penetrations, pipe sleeve

assembly surrounding process penetrations, and miscellaneous/spare mechanical penetrations

that are not associated with a process system are included in the civillstructural screening

described in Section 2.4 of this application. The non meta'l and c6nductor portions (e.g.,

electrical cables and connections) of electrical penetrations are included in the electrical/I&C

screening described in Section 2.5 of this application.

Pressure-Boundary and Fission Product Barrier Function

Tables 2.4.1 and 3.5.2-1 of the LRA list component types 'penetration sleeves, penetration

bellows" and 'seals, gaskets, and moisture barriers." The component type "penetration

sleeves, penetration bellows" includes the cable feed-through assemblies for electrical

penetrations and the closure assemblies for the miscellaneous/spare mechanical penetrations.

The component type "seals, gaskets, and moisture barriers" includes the sealants and gaskets

used in these electrical and mechanical penetration assemblies.

The LRA should have included pressure boundary as an intended function for the "seals,

gaskets, and moisture barriers" component type (for consistency).

Electrical Connection Function

The FNP has both EQ and non-EQ containment electrical penetrations. The cable feedthrough assemblies for electrical penetrations that are subject to 10 CFR 50.49 EQ

requirements are treated as TLAAs and addressed in Section 4.4 of the LRA (refer to Table

3.6.1, item 3.6.1-1). The first two component types in LRA Tables 2.5.1 and 3.6.2-1 include the

cable feed-through assemblies for non-EQ containment electrical penetrations:

* electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

* electrical cables used in instrumentation circuits not subject to 10 CFR 50.49 EQ

requirements that are sensitive to reduction in conductor insulation resistance

Based on its review, the staff finds the applicant's response to RAI 2.4-7 acceptable because it

clarifies the applicant's evaluation of the cable feed-through assembly for containment electrical

penetrations. The civilstructural scoping and screening for the containment structure includes

the pressure-boundary and fission product barrier function of the assembly. The component

types "penetration sleeves, penetration bellows" in LRA Tables 2.4.1 and 3.5.2-1 include the

cable feed-through assemblies for electrical penetrations. The component type 'seals, gaskets,

and moisture barriers" in LRA Tables 2.4.1 and 3.5.2-1 include the sealants and gaskets used

in these electrical assemblies. The applicant also noted that the LRA should have included

pressure boundary as an intended function for the "seals, gaskets, and moisture barriers"

component type.

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Therefore, the staff considers its concern described in RAI 2.4-7 resolved.

The staff's review of the LRA Section 2.4.1 identified a second area'in which it needed

additional information to complete the evaluation of the applicant's scoping and screening

results. Therefore, by letter dated April 12,' 2004, the'staff issued RAI 2.4-8 to determine

whether the applicant properly applied the'scoping criteria of 1O CFR 54.4(a) and the screening

criteria of 10 CFR 54.21 (a)(1). The following describes the staff's RAI:

The staff requires additional information'concerning the possibility that thermal insulation

may serve an intended function, in'accordance with 10 CFR 54.4(a)(2), to control the

maximum temperature of safety-related structures and structural components that meet

10 CFR 54.4(a)(1). POssible examples are (1) maintaining the maximum temperature of

steel and/or concrete -elements of NSSS supports below the levels assumed in the

design basis of the supports; and (2) maintaining the maximum temperature of structural

concrete below the threshold levels of .150 0F for geheral areas and 200 0F for local

areas around hot penetrations. -

Thermal insulation is typically passive and long-lived. If it also serves an intended . function in accordance with 10 CFR 54.4(a)(2), then it meets .the criteria for inclusion

within the scope of license renewal; --Consequently, the applicant was requested to (1)

identify any therrnal insulation at Farley that serves an intended function in accordance

with 10 CFR 54.4(a)(2); (2) describe plant-specific operating ex erience related to

degradation of (a) thermal insulation in general, and (b) thermal insulation that serves an

intended function in accordance with 10 CFR 54.4(a)(2); and (3) describe the scoping

and screening evaluation for thermal irsulation that serves an intended function in

accordance with 10 CFR 54.4(a)(2), including the technical basis fo either inclusion

within or exclusion from the scope of license renewal.

The following provides the applicant's response to' RAI 2.4-8, dated May 10, 2004:

SNC brought thermal insulation into the scope of license renewal when the insulation served an intended

function as defined in 10 CFR 54.4(a). Examples of thermal insulation that have been considered to be

within the scope of license renewal aredcable fire wrap (Reference: SNC responses to RAI 2.3.3.13-2 and

RAI 2.3.3.13-3) and C02 tank Insulatidoi (Reference: .FNP LRA Table 2.3.3-13). In a telephone: conversation held on April 30,2004, the NRC clarified that the scope of this question is limited to insulation

to control the maximum temperature of safety-related structural elements.

The subject thermal insulation at FNP Is not In scope under the provisions of 10 CFR 54.4(a)(1).' Thermal

insulation is not relied upon In FNP's current licensing basis (CLB) to perform any safety related function.

Specifically, the thermal insulation at FNP does not serve a safety-related function to limit the temperature of structural steel and/or concrete elements, including the supports for the NSSS components. 'Thermal

insulation Is neither installed on the containment liner nor installed in any of the hot pipe penetrations.

During normal operations, area and room temperature monitoring activities assure environmental

temperatures are maintained within established limits. 'Environmental control systems that maintain

'temperatures during power operations and are not relied upon for safe shutdown or accident mitigation (e.g., reactor cavity cooling, containment air recirculation system, etc.) are non safety-relatei in FNP's CLB. - -, . ;, : 2. <!

The subject thermal insulation at FNP Is also not In scope under the provisions of 10 CFR 54.4(a)(2) SNC

followed the guidance provided by the Commission and the staff in determining the non safety-related

systems, structures, and components (SSCs) whose failure could prevent satisfactory accomplishment of a

safety function. The Rule's Statement of Considerations (SOC) in Section Ill.c(iii), OBounding the Scope of

Review," provides the following guidance to assist an applicant in determining the extent to which failures

must be considered when applying the scoping criterion:

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"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. [...] However, for license renewal

applicants, the Commission cannot exclude the possibility that hypothetical failures that are part of the CLB

may require consideration of second-, third- or fourth-level support systems."

NUREG-1800 reiterates and expands on the 10 CFR 54.4(a)(2) scoping guidance provided in the Rule's

Statement of Considerations (SOC). NUREG-1800 section 2.1.3.1.2 states:

"... the applicant should consider those failures identified in (1) the documentation that makes up its CLB,

(2) plant-specific operating experience, and (3) industry-wide operating experience that is specifically

applicable to its facility. The applicant need not consider hypothetical failures that are not part of the CLB,

have not been previously experienced, or are not applicable to its facility."

The failure of thermal insulation during a design basis accident in containment (e.g., from damage due to jet

impingement) is evaluated and determined not to cause clogging/blockage of the containment emergency

sumps in the FNP CLB. No other failures of thermal insulation are identified in the CLB.

Thermal insulation is not identified in the FNP CLB as a supporting feature for structural SSCs that perform

safety-related functions. The SNC position that the insulating property of insulation is not within the scope

of the Rule concurs with prior applicants, most recently V.C. Summer Nuclear Station (refer to response to

NRC RAI S AMR-1 in Attachment 1 of VCSNS response dated September 24, 2003).

In addition, SNC has conducted a review of FNP-specific and industry-wide operating experience

associated with insulation. The review has determined that FNP has not experienced degradation of

Insulation impacting structural temperatures. Minor damage to insulation has occurred at FNP, due most

often to mishandling, improper installation, and other human performance errors. A review of industry

operating experience resulted in similar findings for insulation types used at FNP. The degradations

identified were not aging related. SNC has concluded that there are no plausible aging effects for the

subject insulation at FNP that would warrant an aging management program. This determination is

consistent with previous applicants and NRC staff determinations (e.g., Safety Evaluation Report for the

Ucense Renewal Application for the Calvert Cliffs Nuclear Plant, December 1999, Section 2.2.3.13.2.1).

Thus, under 10 CFR 54.4, SNC maintains that insulation will not fail in a manner that could prevent

satisfactory accomplishment of any of the safety-related functions identified under 10 CFR 54.4(a)(1), or in

a manner that could adversely impact the function of a safety-related SSC.

There has been specific ongoing discussion between the NRC Staff and SNC with regard to insulation used

on the reactor coolant system (RCS) components and the impact of the loss of the insulation upon concrete

temperatures inside the containment. As stated above, the failure of the insulation is not required to be

considered, since that failure is neither considered in the FNP CLB nor identified through operating

experience. However, there is additional defense-in-depth beyond the RCS insulation that assures

concrete temperature limits are not exceeded. Technical Specification 3.6.5 limits bulk containment

temperature to 120 F or below. Various containment fans limit hot spots such that SNC does not expect

containment concrete temperature thresholds would ever be exceeded. This position is in agreement with

the positions of prior applicants, who have also not included the RCS system insulation within the scope of

10 CFR 54.4(a).

In conclusion, specific applications of thermal insulation at FNP are in scope under the criteria of

10 CFR 54.4(a)(3)., Thermal insulation at FNP is not in scope under the provisions of 10 CFR 54.4(a)(1) or

10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant's response to RAI 2.4-8 acceptable because

the second paragraph of the RAI response provides a sufficient technical basis to conclude that

thermal insulation does not serve an intended function to control the maximum temperature of

safety-related structural elements. As the applicant indicated in the first paragraph of the RAI

response, "In a telephone conversation held on April 30, 2004, the NRC clarified that the scope

of this question is limited to insulation to control the maximum temperature of safety-related

structural elements."

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The staff has not evaluated the remaining par phs of the RAI response beyond the second

paragraph because they do not relate directly to closure of RAI 2.4-8. Therefore, the finding of

acceptability noted above is based upon the first two paragraphs of the RAI response.

The staff considers its concern described in RAI 2.4-8, for the specific intended function of

controlling the maximum temperature of safety-related structural elements; to be resolved.

2.4.1.3 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 the containment SCs: The staff'cohcludes that the applicant has adequately

identified the containment 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 containment SCs that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.2 "Other StructuressThe sections below discuss the following other structures:

* auxiliary building

* ' diesel generator building ' * ~'turbine building -

* utility/piping tunnels

* '-water control structure - -

* '' steel tank'structures (foundation arid retaining walls) -

'- yard structures

2.4.2.1 Auxiliary Building -

2.4.2.1.1 Summary of Technical Information in the Application

In Section 2.4.2.1 of the LRA,' the applicant'described the auxiliary building.

In Table 2.2-1 e of the LRA, the applicant identified the following criteria it used to determine the

auxiliary building SSCs that ar'e withirithes'cope of license renewal:

* safety-related (10 CFR 54.4(a)(1)) - * nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* anticipated transient without scram (10 CFR 54.4(a)(3)) * station blackout (10 CFR'54.4(a)(3)) -'-

In Table 2.42.1 of the LRA, the apoiicanit identified the-auxiliary building component types that

are within the scope of license renewal and subject to an AMR, including compressible joints

and seals, concrete-(6xterior abovegrade),'concrete (exterior belowgrade), concrete,

(foundation), concrete (interior), concrete (roof slab);'nonfire d6ors,'fire-doors, fire seals,

masonry walls (all), new fuel storage racks (storage rack assembly), penetration sleeves, spent

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fuel storage racks (storage racks), steel components (all structural steel), and steel

components (liners).

2.4.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.1 and the referenced FNP FSAR Sections 2B.6.3, 3.8,

and 9.1. The staff conducted its review in accordance with the guidance described in Section

2.4 of NUREG-1 800.

In its evaluation, the staff reviewed the FSAR to determine if the applicant identified all

structural or component functions of the auxiliary building as an intended function, in

accordance with the requirements of 10 CFR 54.4(a). The staff did not identify any omissions.

The staff then evaluated that the passive, long-lived components were subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff's review of the LRA Section 2.4.2.1 identified one area in which it needed clarification

to complete the evaluation of the applicant's scoping and screening results. Therefore, by letter

dated March 2, 2004, the staff requested a clarification to determine whether the applicant

properly applied the scoping criteria of 10 CFR 54.4(a). The following describes the staff's

request for clarification:

LRA Section 2.4.2.1 states that the Auxiliary Building is a reinforced concrete slab,

bearing directly on the Lisbon foundation. However, FSAR Section 3.8.4.1A indicates

that portions of the foundation consist of a reinforced concrete slab placed over 9 ft. 5

in. of concrete fill, which in turn bears on the Lisbon formation. FSAR Section 3.8.4.1A

further indicates that another portion of the foundation consists of a reinforced concrete

slab placed over 30 ft. of compacted fill, which in turn rests on a reinforced concrete mat

bearing directly on the Lisbon formation. In addition, FSAR Section 3.8.5.1 B indicates

that the eastern section of the Auxiliary Building is supported on spread footings which

bear on the Lisbon formation, and also states that loads are transmitted through cast-in

place reinforced concrete columns. The applicant was requested to clarify whether all

the concrete structural elements of the Auxiliary Building foundation (as described in the

FSAR) are within the scope of license renewal. If not, provide the technical basis for

their exclusion.

In its response, dated March 31, 2004, the applicant clarified that all the concrete structural

elements of the auxiliary building foundation (as described in the FSAR) are within the scope of

license renewal. The staff finds the applicant's clarification acceptable.

2.4.2.2 Diesel Generator Building

2.4.2.2.1 Summary of Technical Information in the Application

In Section 2.4.2.2 of the LRA, the applicant described the diesel generator building.

In Table 2.2-1 e of the LRA, the applicant identified the following criteria it used to determine the

diesel generator building SSCs that are within the scope of license renewal:

safety-related (10 CFR 54.4(a)(1))

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* nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* station blackout (10 CFR 54.4(a)(3))'

In Table 2.4.2.2 of the LRA, the applicant identified the diesel generator building component

types that are within the scope of license renewal and subject to an AMR, including

compressible joints and seals, concrete (exterior abovegrade), concrete (foundation), concrete

(interior), concrete (roof slab), nonfire doors, fire d6orsifire seals, masonry walls (all),

penetration sleeves, and steel components (all structural steel).

2.4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.2 and the referenced FNP FSAR Sections 2B.6.5 and

3.8. The staff conducted its review in accordance with the guidance described in Section 2.4 of

NUREG-1800.

In its evaluation, the staff reviewed the FSAR to determine if the applicant identified all diesel

generator building structural or component functions as an intended function, in accordance

with the requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff

then evaluated that the passive, long-lived components were' subject to an AMR, in accordance

with 10 CFR 54.21 (a)(1).

The staff found that the applicant included those portions of the diesel generator 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 2.4.2.2. .Table 2.4.2.2 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 Turbine Building

2.4.2.3.1 Summary of Technical Information in the Application

In Section 2.4.2.3 of the LRA, the applicant described the building.

In Table 2.2-1 e of the LRA, the applicant identified the criteria it used to determine the turbine

building SSCs that are within the scope of license renewal:

* nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* -- fire protection (10 CFR 54.4(a)(3)).-- anticipated transient without scram (10 'CFR 54.4(a)(3))

* station blackout (10 CFR 54.4(a)(3))

In Table 2.4.2.3 of the LRA, the applicant identified the building component types that are within

the scope of license renewal and subje6t to an AMR, including concrete (exterior abovegrade), concrete'(exterior belowgrade), concrete (foundation), concrete (interior), concrete (roof slab),

and steel components (all structural steel).

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2.4.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.3 and the referenced FNP FSAR Section 2B.6.9. The

staff conducted its review in accordance with the guidance described in Section 2.4 of

NUREG-1800.

In its evaluation, the staff reviewed the FSAR to determine if the applicant identified all

structural or component functions of the turbine building as an intended function, in accordance

with the requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff

then evaluated that the passive, long-lived components were subject to an AMR, in accordance

with 10 CFR 54.21 (a)(1).

The staff found that the applicant included those portions of the turbine 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 2.4.2.3. Table 2.4.2.3 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).

2.4.2.4 Utility Piping Tunnels

2.4.2.4.1 Summary of Technical Information in the Application

In Section 2.4.2.4 of the LRA, the applicant described the utility/pipping tunnels.

In Table 2.2-1 e of the LRA, the applicant identified the following criteria it used to determine the

utility piping tunnel SSCs that are within the scope of license renewal:

* safety-related (10 CFR 54.4(a)(1))

* nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* anticipated transient without scram (10 CFR 54.4(a)(3))

In Table 2.4.2.4 of the LRA, the applicant identified the utility/piping tunnels component types

that are within the scope of license renewal and subject to an AMR, including compressible

joints and seals, concrete (exterior abovegrade), concrete (exterior belowgrade), and structural

steel.

2.4.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.4 and the referenced FNP FSAR Section 3.8. The staff

conducted its review in accordance with the guidance described in Section 2.4 of NUREG-1800.

In its evaluation, the staff reviewed the FSAR to determine if the applicant identified all

structural or component functions of the utility/piping tunnels as an intended function, in

accordance with the requirements of 10 CFR 54.4(a). The staff did not identify any omissions.

The staff then evaluated that the passive, long-lived components were subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff found that the applicant included those portions of the utility/piping tunnels that meet

the scoping requirements of 10 CFR 54.4 within the scope of license renewal and identified

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them as such in LRA Section 2.4.2.4. Table'2 4.2.4'0f thed'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).

2.4.2.5 Water Control Structures - : -

2.4.2.5.1 Summary of Technical Informatio 'iri the' Application

In Section 2.4.2.5 of the LRA, the applicant ddscribed the water control structures.

In Table 2.2-1 e of the LRA, 'the applicant identified the following 'criteria it used to determine the

water control structure SSCs that are within the' scope of license renewai:

* ' safety-related (10 CFR 54.4(a)(1))- -- ' -' --

* nonsafety-related that can prevent aa-sifety-'related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))' C - -

In'Table 2.4.2.5 of the LRA, the applicant identified the water control structures component

types that are within the scope of license renewal and subject to an AMR, including concrete

(exterior abovegrade), concrete (exterior bel6wrade), concrete (foundation), concrete

(interior),' concrete (roof slab),'nonf ire doorsP, earthen water-control structures (dams,

embankment), fire doors, fire seals, masonry walls (all), steel components (all structural steel),

stop logs, and traveling screen. ' '

2.4.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.5 and the referenced FNP FSAR Sections 2.4.8.1,-2B.6,

2B.7, and 3.8. The staff conducted its review in accordance with the guidance described in

Section 2.4 of NUREG-1800. -

In its evaluation, the staff reviewed the FSAR to determine if the applicant identified all.

structural or comrponent functions'of the water control structures as an intended function, in

accordance with the requirements of 10 CFR 54i4(a); "The staff did not identify 'any omissions.

The staff then evaluated that the passive, lonrg'ived components were subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1). ' - -

The staff's review of the LRA Section 2.4.2.5 identified one area in which it needed additional

information to complete the evaluation of th6-apolicant'` scoping and screening results. -

Therefore, by letter dated February 13, 2004, the staff issued RAI 2.4-5 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 describes the staff's RAI 2.4-5: - r

-To completely clarify the scop'e of the ultimate heat sink structures, provide the following

additional information: - . - '

(1) Describe the River Water system that transports water from the river water

-intake structure to the storage pond and explain why the structures iri this

system are not within the scope oflicense renewal. Also, can there bea reverse

flow of water that can reduce the water level in the storage' pond,' and

consequently jeopardize the ultimate heat sink? What structures would prevent

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such an occurrence and are they included in the LR scope?

(2) In LRA Section 2.4.2.5, the discussion of the Storage Pond Spillway Structure

does not include a description of the Spillway Intake and Discharge Canals.

These canals are described in FSAR Section 2.4.8.2. Further information on

these canals (channels) is provided in FSAR Section 2.4.14.2, which states:

The spillway channel shall be inspected after each operation of sufficient

magnitude to have a potential for erosion. A discharge of 80 ft3/s corresponding

to a pool at elevation 187.0 has been selected as the minimum flow for which

inspection shall be required. At this discharge the flow in the grassed discharge

channel would have an average velocity of about 1.3 ft per second with a flow

depth of 1.3 ft. The pond level will be monitored in the control room. Whenever

the operator observes or inspection of the chart indicates that the pool level is

greater than or equal to elevation 187.0, the channels and structure shall be

inspected at the end of the discharge period, as required by the Technical

Requirements Manual. Eroded areas that affect or can affect the channel bank

slopes or that are more than 4 ft deep should be promptly repaired. Because of

the expected infrequent use of the spillway, the channels and structure shall also

be inspected biennially, as required by the Technical Requirements Manual.

In light of the above information, clarify whether the Spillway Intake and

Discharge Canals are within the scope of license renewal. If not, explain why

not.

In its response to RAI 2.4-5, part 1, dated March 12, 2004, the applicant stated the following:

Except for some pond level switches and associated tubing (addressed in LRA Tables 2.3.3.5 and 2.3.3.7),

the river water system at FNP is not in the scope of license renewal because it does not meet the criteria of

10 CFR 54.4(a). The storage pond is supplied from the river water system and the supply line outlet is

physically located above the storage pond's normal water level as well as above the minimum emergency

water level. Although the supply line outlet is slightly below the pond's maximum possible flood level

(spillway elevation), any siphoning effect would be broken well before the pond water level reached the

normal elevation or the minimum emergency elevation. Any reverse flow of water from the storage pond to

the river via a siphoning effect in the river water system cannot deplete that portion of the pond's volume

credited for emergency use. Therefore, the pond volume relied upon in an emergency cannot be depleted

via the river water system.

In its response to RAI 2.4-5, part 2, dated March 12, 2004, the applicant stated the

following:

The Spillway Intake and Discharge Canals are earthen canal design features for directing the spillage flow

from the emergency cooling pond (ultimate heat sink) resulting from an unusual rainfall/flooding event

(exceeding the maximum 5-year storm per UFSAR Section 2.4.14.2). The Spillway Intake and Discharge

Canals do not perform a safe shutdown or accident mitigation function and therefore do not meet the

scoping criteria of 10 CFR 54.4(a)(1). These features do not perform a function that demonstrates

compliance with the Commission's regulations for any of the events listed in 10 CFR 54.4(a)(3). In addition,

there is no failure mode for the canals that can adversely affect a safety related function or the performance

of safety related equipment and therefore do not meet the scoping criteria of 10 CFR 54.4(a)(2). The

canals are inspected periodically and after any significant discharge event as stated in UFSAR Section

2.4.14.2, therefore the current licensing basis ensures the material condition of the canals is maintained.

UFSAR Section 2.4.8.2 states for the canals that 'Additional erosion protection is not required since the

spillway structure is designed to prevent impairment of emergency cooling pond banks in the unlikely event

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of extreme channel erosion'and degradation." Therefore, the spillway structure 'protects" the emergency

cooling pond banks and is in scope for license renewal, but the canals do no meet any of the

10 CFR 54.4(a) scoping criteria. (The Storage Pond Spillway Structure is in the scope of Ucense Renewal

as indicated in LRA Table 2.2-1 e and Section 2.4.2.5.)

In summary; these canals do not satisfy the criteria as defined in 10 CFR 54.4(a) and so are not within the

scope of license renewal.

Based on its review, the staff finds the applicant's response to parts 1 and 2 of RAI 2.4-5.

acceptable because it clearly and concisely describes the technical basis for excluding the river

water system and the spillway intake and discharge canals from the scope of license renewal.'

The staff concurs with the applicant's conclusions.

Therefore, the staff considers its concern described in RAI 2.4-5 resolved.

2.4.2.6 Steel Tank Structures (Foundations and Retaining Walls)

2.4.2.6.1 Summary of Technical Information in the Application

2 l4.6 of the the ap .A . th'. ..

In Section 2.4.2.6 of the LRA, the applicant described the'steel tank'structures.

In Table 2.2-1 e of the LRA, the applicant identified the following criteria it used to determine the

steel tank structure SSCs that are within the scope of license renewal.

* safety-related (10 CFR 54.4(a)(1))

* fire protection (10 CFR 54.4(a)(3)) . .

In Table 2.4.2.6 of the LRA, the applicant identified the steel tank structures (foundation and

retaining walls) component types that are within the scope of license renewal and subject to an"

AMR, including bolting, concrete pedestal, concrete (exterior abovegrade shielding and

retaining walls), concrete (foundation), and steel components (all structural steel).

2.4.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.6 and the referenced FNP FSAR Sections 3.8, 6.2.2, 6.3,

9.2.7, 9.5.4, and 9B.4.2.1. The staff conducted its review in accordance with the guidance

described in Section 2.4 of NUREG-1800.,

In its evaluation, the staff reviewed the FSAR to determine' if the applicant identified all

structural or component functions of the steel tank structures (foundations and retaining walls)

as an intended function, in accordance with the requirements of 10 CFR 54.4(a). The staff 'did'

not identify any omissions. The staff then evaluated that the passive, long-lived componentswere subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

The staff's review of the LRA Section 2.4.2.6 identified one area in which it needed clarification

to complete the evaluation of the applicant's scoping and screening results. Therefore, by letter

dated March 2, 2004, the staff requested a clarification to determine whether the applicant

properly applied the scoping criteria of 10 CFR 54.4(a).- The following describes the staff's

request for clarification.

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I
Section 2.4.2.6, uSteel Tank Structures (Foundations and Retaining Walls)," of the LRA states

the following:

The Emergency Diesel Generator Fuel Oil Storage Tanks are 40,000 gallon, seismic

category I underground tanks. The tanks are supported by poured concrete and buried

for protection.

Table 2.4.2.6 of the LRA'does not specifically identify a component type to cover a buried

concrete foundation. Therefore,: the staff requested the applicant to confirm that the subject

buried concrete foundation is within-the scope of license renewal and to identify the component.

type in LRA Table 2.4.2.6 that includes this foundation.

In its response, dated March 31, 2004, the applicant confirmed that the buried concrete

foundation for the EDG fuel oil storage tanks is in the scope of license renewal and further

stated the following:

The component type "Concrete: Foundation" in LRA Table 2.4.2.6 is applicable to the Emergency Diesel

Generator Fuel Oil Storage Tanks buried concrete foundation. The buried environment is identified in LRA

Table 3.5.2-7 component type "Concrete:. Foundation" with a corresponding environment of Below Grade,

and is inclusive of the Emergency Diesel Generator Fuel Oil Storage Tanks buried concrete foundations.

The staff finds the applicant's clarification acceptable.

2.4.2.7 Yard Structures

2.4.2.7.1 Summary of Technical Information in the Application

In Section 2.4.2.7 of the LRA, the applicant described the yard structures.

In Table 2.2-1 e of the LRA, the applicant identified the following criteria it used to determine the

yard structure SSCs that are within the scope of license renewal-

* nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* station blackout (10 CFR 54.4(a)(3))

In Table 2.4.2.7 of the LRA, the applicant identified the yard structure component types that are

within the scope of license renewal and subject to an AMR, including bolting, concrete

(foundation), equipment frames and housings, fire door, masonry wall, and steel components

(all structural steel).

2.4.2.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.7 and the referenced FNP FSAR Sections 8.2.1,

91.4.2.1, 11.3.7, and 1 1.5. The staff conducted its review in 'accordance with the guidance

described in Section 2.4 of NUREG-1 800.

In its evaluation, the staff reviewed the FSAR to determine if the applicant identified all

structural or component functions of the yard structures as an intended function, in accordance

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with the requirements of 10 CFR 54.4(a). The staff did not identify any omissions. The staff

then evaluated that the passive, long-lived components were subject to an AMR, in accordance

with 10 CFR 54.21 (a)(1).'

The staff's review of the LRA Section 2.4.2.7 identified one area in which it needed additional

information to complete the evaluation of the applicant's scoping and screening results.

Therefore, by letter dated February 13, 2004; the staff issued RAI 2.4-2 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 describes the staff's RAI:

In LRA Section 2.4.2.7, the plant vent stacks are identified as "yard structuresn -_

However, in the first paragraph, it is'stated 'The plant vent'stacks are evaluated as part

of the Auxiliary and Radwaste Ventilati6n'System in Section 2.3.3.10." In LRA Section

2.4.2.7, under the heading "Plant Vent Stack", it states 'The'vent stack-is a Seismic

Category I structure that is not required for safe shutdown" and "The vent stack is a non

safety-related structure but its function is to maintain its structural integrity during a

design basis event such that it does not impact other SR structures or components." It

appears that the plant vent stacks are in the LR scope for seismic 11/I considerations.

LRA Table 2.3.3.10 does not list the plant vent stacks as a "Component Type." Please

clarify which section of the LRA Chapter 2 includes the plant vent stacks (and their

foundations) in its scope, and also identify where the AMR for the plant vent stacks (and

their foundations) is explicitly listed in Chapter 3.5 tables of the LRA.

In its response to RAI 2.4-2, dated March 12, 2004, the applicant stated the following:

The plant vent stacks are In LR scope as meeting the criteria identified in 10 CFR 54.4(a)(2).

The last sentence of the first paragraph of Section 2.4.2.7, "Yard Structures," which is quoted in the RAI,

should have read (changes indicated in bold italics):

'The plant vent stacks' noble gas radiation monitors are evaluated as part of the Auxiliary and Radwaste

Ventilation System in Section 2.3.3.10."

The vent stack structural elements are addressed in LRA Sections 2.4.2 and 3.5 as discussed below. - i - *., -,

Each unit's plant vent stack Is a steel tubular structure used as a gaseous release point for various process,

filtration and ventilation systems:-1 Each plant vent stack is anchored at its base to the Auxiliary Building's

ground level (155' elev.) floor slab, and laterally, restrained where it exits the Auxiliary Building roof. Lateral

restraints provided between the top of the stack and the'roof are mounted to the containment structure.

Supportirig steel for the vent stack is addressed in the Yard Structures evaluation in the component type

'Steel components: All Structural Steel" In Tables 2.4.2.7 and 3.5.2-8. The vent stack foundation is

addressed in the Auxiliary Building evaluation in the component type 'Concrete: Interior" listed in Tables

2.4.2.1 and 3.5.2-2. . , ;. * - , . . , -

The tubular steel portion of the vent stack Is not specifically addressed in the LRA tables but is shown in the

Structural Monitoring Program scope for license renewal as detailed In LRA Section B.4.3.5. Table 2.4.2.7,

'Yard Structures Component Types Subject to Aging Management Review and their Intended Functions,"

should have Included the following line item: , -

[ Component Type . | . Intended Function |

Steel Vent Stack NSR Structural Support

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Correspondingly, the aging management review summary for Yard Structures in LRA Table 3.5.2-8 should

have included the following entry.

Component Intended Material Environment Aging Effect Aging NUREG-180 Table Note #

Type Function .. . Requiring Management 1 Volume 2 1

Management Programs Item Item

Steel Vent NSR Carbon Outside Loss of . Structures 111.836.1-a 3.5.1- C

Stack Structural Steel Material Monitoring 29

Support _Program

Based on its review, the staff finds the applicant's response to RAI 2.4-2 acceptable because it

corrects and clarifies the evaluation of the plant vent stacks contained in the LRA. The

applicant identified a correction to LRA Section 2.4.2.7 and additions to LRA Tables 2.4.2.7 and

3.5.2-8, which clearly indicate that the structures scope includes the plant vent stacks and LRA

Section 3.5 includes the AMR results.

Therefore, the staff considers its concern described in RAI 2.4-2 resolved.

2.4.2.8 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 the other structures. The staff concludes that the applicant has adequately identified

the other structures and associated 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 other

structures and associated components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.4.3 Component Supports

2.4.3.1 Summary of Technical Information in the Application

In Section 2.4.3 of the LRA,' the applicant stated that component supports group includes

specific types of support elements located within in-scope structures. Physical interfaces exist

with the structure, system,Ior component being supported and with the building structural

element to which'the su6pport is anchored. As a primary function, a support anchors the

supported element for DBEs so the supported element can perform its intended function. The

individual structure's description identifies the supports within a structure that are included in

the scope of license renewal for FNP. The in-scope items include support members, welds,

bolted connections, anchorage (including base plate and grout) to the building structure, spring

hangers, guides, vibration isolators, and building concrete at bolt locations.

The discussions of the component support elements fall under the following headings:

* supports for ASME and non-ASME piping and components

* supports for cable trays, conduit, HVAC ducts, tube track, instrument

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anchorage of racks, panels, cabinidets, ''enclosures for electrical equipment and

instrumentation - . .

* supports for emergency diesel generator, HVAC system components, and other

miscellaneous' -

* supports for platforms, pipe whip restraints, jet impingement shields, and other

miscellaneous structures

In Table 2.2-1 e of the LRA, the applicant identified the following criteria it used to determine the

component support SSCs that are within'the scope of license renewal:

* ' safety-related (10 CFR 54.4(a)(1))' -

* 'onsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* ' -fire protection (10 CFR 54.4(a)(3)) - - -

* anticipated transient without scram (10 CFR 54.4(a)(3))

* -station blackout (10 CFR 54.4(a)(3))

In Table 2.4.3 of the LRA, the applicant identified thei component sup'port compornent types that

are within the scope of license renewal and subject to an AMR, including battery racks;-RPV

supports; American Society of Mechanical Engineers'(ASME) and no'n-ASME piping and

component support members (support members, welds, bolted connections, support anchorage

to building structure); constant and variable load spring hangers,_guides' and stops; sliding

surfaces and vibration isolators (for ASME piping and components); cable tray, conduit, HVAC

ducts, tube track (support members welds, bolted connections, support anchorage to building

structure); and racks, panels, and cabinets (support members, welds, bolted connections,

support anchorage to building structure).

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 and the referenc6d FNP FSAR Sections 3.2, 3.6.5.1,

3.7.3.14, 3.8, 5.5, 9.4, and Appendix 3K (Attachment B). The staff conducted its review in

accordance with the guidance described in Section 2.4 of NUREG-1800.

In its'evaluation,' the'staff reviewed the FSAR t6 determine if th6 applicant identified all

structural or component functions of the component supports as an intended function, in

accordance with the requirements of 10 CFR 54.4(a). The staff did not identify any omissions.

The staff then evaluated that the passive, longdied components were subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

The staff's review of the LRA Section 2.4:3 identified one area in which it needed clarification to

complete the evaluation-of the applicant's scoping and screening results. Therefore, by letter

dated March 2, 2004, the staff requested a&clarification 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 describes the staff's request for clarification:

LRA Table 2.3.1.3 identifies Pressurizer-Support Lugs' and 'Pressurizer Support Skirt and Flange," with a

'Structural Support" intended function. -These component types appear to be the ASME Class 1 component support for the pressurizer. However, LRA Section 2.4.1.4 'Containment Internal Structures" states "RCS

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I

supports are addressed in Section 2.4.3, -Component Supports." LRA Section 2.4.3.1 'Supports for ASME

and Non-ASME Piping and Components describes the'supports for the reactor vessel, steam generator,

reactor coolant pumps, and pressurizer. In order to clarify the treatment of pressurizer supports in the LRA,

please

(1) verify that the ASME Class 1 component supports for the reactor vessel, steam generators, reactor

coolant pumps, and pressurizer are included in the Structures scope, under Component Supports.

In LRA Table 2.4.3, only 'RPV Supports' are explicitly identified.

(2) explain the Pressurizer-Support Lugs and Pressurizer-Support Skirt and Flange entries in LRA

Table 2.3.1.3.

In its response, dated March 31, 2004, the applicant confirmed that the structures scope

includes the ASME Class 1 component supports for the reactor vessel, steam generators'

RCPs, and pressurizer under component supports in LRA Section 2.4.3.1. LRA Table 2.4.3

lists RPV supports as a unique component type. Table 2.4.3 of the LRA includes supports for

steam generators, RCPs, and pressurizers under the component type "ASME and non-ASME

piping and component support members."

The applicant further explained that the pressurizer support skirt and flange is welded to the

bottom portion of the pressurizer vessel, and the pressurizer support lugs are welded to the

upper head of the pressurizer and are integral with the pressurizer. Section 2.3 of the LRA

evaluates these pressurizer subcomponents with the pressurizer. Section' 2.4.3 of the LRA

evaluates structural support members interfacing with the pressurizer support lugs and support

skirt and flange as structural components. The staff finds the applicant's clarification

acceptable.

2.4.3.3 Conclusion

The staff reviewed the LRA and related structuralcomponent information to determine whether

the applicant identified all SSCs that should be within the scope of license renewal. The staff

found no omissions. In addition, the staff performed an independent assessment to determirie

whether the applicant identified all components that should be subject to an AMR. The staff

found no omissions. On the basis of its review, the staff concludes that the' applicant has

adequately identified the components of the component supports that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the component supports that are 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 of electrical and l&C systems at FNP

for license renewal. According to 10 CFR 54.21 (a)(1), an applicant must identify and list SCs

subject to an AMR. These are passive, long-lived SCs that are within the scope of license

renewal. To verify that the applicant properly implemented its methodology, the staff focuses

its review on the implementation results. Such a focus allows the staff to confirm that the: -

applicant has omitted no electrical system components that are subject to an AMR. If the

review identifies no omission, the staff has the basis to find that the applicant has identified the

electrical system components that are subject to an AMR.

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On the basis of this review, the staff requested additional information during the staff's audit of

the FNP License Renewal Prodradm from November 3-7, 2003. Thfe staff also requested

additional information in a letter dated Marcfi 29,' 2004. The applicant responded to these

requests for additional information in letters to the staff dated December 5, 2003, and April 29,

2004.

Staff Evaluation Methodology

The staff evaluated the information provided in the LRA in the same manner for all electrical

and l&C systems. Through the review, the staff determined if the applicant identified the SSCs

for a specific electrical or l&C system that appeared 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

were subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

Scoping. To perform its evaluation, the staff reviewed the applicable'LRA section and

associated component drawings, focusing its 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 FSAR, for each electrical anrd l&C component to determine' if the

applicant had omitted components with intended futnctions 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 specified all intended fi~nctions delineated under 10 CFR 54.4(a). If it

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 th'se SCs with intended fuinctions, the staff sought to

determine if the functions are performed with mbving parts or a change in c6nfiguratiori 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 did not meet either of these criteria,

the staff sought to confirm that these electrical and l&C components were subject to an AMR,

as required by 10 CFR 54.21(a)(1). If it iden'tifi6d discrepancies, the 'staff requested additional

information to resolve them.

2.5.1 Summary of Technical Information in the"Application

For electrical and l&C systems, the applicant used'a'bounding approach as described in NEI

95-10. The applicant identified electrical and l&C component types subject to an AMR by

applying the criteria of 10 CFR 54.21 (a)(1). The applicant reviewed these electrical commodity

groups (determined to be passive) to identify those that are not subject to replacement based

on a limited qualified life' or specified period. Based on its review, the' applicant determined that

the following electrical and l&C c6mponent c66mmodity group's are subject to an AMR:

electrical cables and connectors not subject to 10 CFR 50.49 EQ requirements

* electrical cables'used in instrumentation circuits not subject to 10 CFR 50.49 EQ

requirements that are sensitive to reduction in conductor insulation resistance . c o- . . *; , * ' - - . - -orated

* electrical connectors not subject to 10 CFR 50.49 EQ requirements exposed to borated

'2-173
water leakage

* inaccessible medium voltage electrical cables not subject to 10 CFR 50.49 EQ

requirements

* fuse holders

* high voltage insulators

* metal enclosed cable bus

* oil-static cable

* switchyard bus

* transmission conductors

All other electrical and I&C component commodity groups are either active, subject to

replacement based on a qualified life or specified time period, or not subject to an AMR

because they do not perform any intended functions.

In Table 2.5.1 of the LRA, the applicant listed the electrical component types subject to AMR

and their intended functions.

In Table 2.2-1 f of the LRA, the applicant identified the plantwide electrical and l&C systems and

structures within the scope of license renewal. It used to the following criteria to determine the

plantwide electrical and l&C systems and structures that are within the scope of license

renewal:

* safety-related (10 CFR 54.4(a)(1))

* nonsafety-related that can prevent a safety-related function (10 CFR 54.4(a)(2))

* fire protection (10 CFR 54.4(a)(3))

* environmental qualification (10 CFR 54.4(a)(3))

* anticipated transient without scram (10 CFR 54.4(a)(3))

* station blackout (10 CFR 54.4(a)(3))

* pressurized thermal shock (10 CFR 54.4(a)(3))

2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.5 to determine whether 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 its evaluation, the staff selected system functions described in the FSAR that were set forth

in 10 CFR 54.4 to verify that the applicant did not omit components having intended functions

from the scope of the Rule. The staff also reviewed drawings and focused on components that

the applicant did not identify as subject to an AMR to determine if it had omitted any

components.

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Section 2.5, Table 2.5.1, of the LRA does not include'the transmission connections in the AMR.

During its audit, the staff requested that the applicant clarify why it did not include transmission

connections with transmission conductors. In response to the staff request, in a letter dated

December 5, 2003, the applicant stated that the component type "transmission conductors" is a

general category and does not itemize all components within the category. The component

type 'transmission conductors" includes the transmission conductors and the hardware used to

secure the conductors to high-voltage insulators. The AMR for transmission conductors

includes transmission connections. Based on this information, the staff concludes that the

applicant did not omit transmission connections at FNP.

Table 2.5.1 of the LRA lists electrical cables and connectors subject to an AMR. However, it

does not include splices, terminal blocks, and fuse holders. The staff requested the applicant to

clarify why it did not include splices, terminal blocks, and fuse holders in the AMR. In a letter

dated December 5, 2003; the applicant responded that the category "electrical cables and

connections not subject to 10 CFR 50.49 EQ requirements" includes splices, connectors,

terminal blocks, and fuse holders. The AMR for connections include splices, terminal blocks,

and fuse holders. Based on this information, the staff concludes that the applicant did not omit

splices, terminal blocks, and fuse holders at FNP.

Table 2.2-1f of the LRA lists nonsegregated buses as SCs within the scope of license renewal.

However, scoping and screening results (Section 2.5 of the LRA) do not include these

components in the AMR. Nonsegregated buses are long-lived, passive components and should

be included in an AMR.: The staff requested the applicant to clarify why it did not include the

nonsegregated buses in the AMR. The applicant responded, in a letter dated December.5,

2003, that the nonsegregated buses item listed in Table 2.2-1 f is the same equipment as the

metal enclosed bus listed in Table 2.5.1. The applicant performed an AMR for the metal

enclosed bus. Based on this information, the staff concludes that the applicant did not omit the

nonsegregated phase buses at FNP.

Section 2.5 of the LRA does not include non-EQ electrical penetrations in the AMR. Non-EQ

electrical penetrations within the scope of license renewal are considered passive, long-lived

components that require an AMR. The staff requested the applicant to clarify if there is any

non-EQ electrical penetration and why there is no non-EQ containment penetration AMP. The

,applicant responded, in a letter dated December 5, 2003, that FNP has both EQ and non-EQ

electrical penetrations. The Inservice Inspection Program covers the pressure boundary

function of both EQ and non-EQ electrical penetrations. The Non-EQ Cables and Connections

Program will cover the electrical portions of penetrations that provide a connection function for

nonsafety-related equipment. -Based on this information, the staff concludes that the applicant

has adequately identified the non-EQ electrical penetrations that are subject to an AMR.

Table 2.2-li of theLRA lists grounding systems asa system that is not within the scope of

license renewal. The staff requested the applicant to explain why it omitted the grounding

system from the scope of license renewal. In a letter dated December 5, 2003, the applicant

responded that uninsulated ground conductors are electrical conductors (e.g., copper cable, J

copper bar,- steel bar) that are used to make ground connections for electrical equipment.

Ground connections are made to electrical equipment housing and enclosures, as well as metal

structures such as cable tray systems and building structural steel. The ground conductors are

isolated from the electrical operating circuits.- Uninsulated ground conductors have the I

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following basic functions:

* provide a common electrical ground reference for all electrical and electronic equipment

* enhance the capability of the electrical system to withstand electrical system

disturbances (e.g., electrical faults, lightning surges) for equipment and personnel

protection

Uninsulated ground conductors do not perform or support any safety-related functions or any of

the functions identified in 10 CFR 54.4(a). Uninsulated ground conductors are not relied on to

remain functional during or following any DBE. Therefore, no failures of insulated ground

conductors could prevent satisfactory accomplishment of any of the functions identified in

10 CFR 54.4(a).

The accident analysis in Chapter 15 of the FSAR did not consider any failures of uninsulated

ground conductors. Because the analysis did not consider any failures, a failure mode and

effects analysis is not required. The FNP has not experienced an age-related failure of an

uninsulated ground conductor. Because the FNP CLB does not include failures of uninsulated

ground conductors, FNP has not experienced such failures previously, and such failures have

not been reported as industry operating experience, the failure of uninsulated ground

conductors does not require consideration.

Based on this response, the staff concludes that uninsulated ground conductors do not perform

or support any safety-related functions or any of the regulated events identified in

10 CFR 54.4(a). Therefore, the passive electrical commodity of uninsulated ground conductors

is not within the scope of license renewal.

In ISG-2, "NRC Staff Position on License Renewal Rule (10 CFR 54.4) As It Relates to the

Station Blackout Rule (10 CFR 50.63)," the staff states the following:

The offsite power systems consist of a transmission system (grid) component that

- provides a source of power and a plant system component that connects the power

source to a plant's onsite'electrical distribution systems' which power safety equipment.

For the purpose of the license renewal rule, the staff has determined that the plant

system portion of the offsite power system that is used to connect the plant to the offsite

power source should be included within the scope of the rule.

The staff requested the applicant to provide a detail description of the FNP recovery path and

discuss how it included the recovery path within the scope of license renewal rule, in

compliance with ISG-2. -The staff also requested the applicant to clarify how the offsite power

source feeds startup transformers 2A, 1 A, and 1 B without using breakers 830, 820, and 800. In

response to the staff's request, the applicant, in a letter dated April 29, 2004, responded that,

per ISG-2, the FNP LRA scope for SBO 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 the circuit breaker and transformer and

onsite electrical distribution system, the associated control circuits, and structures in the path to

restore offsite power.

The applicant further explained that multiple sources in the 230 kV and 500 kV switchyards can

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feed startup transformers 1 A,1 B, 2A, and 2B. The path shown on the LRA boundary drawings

(D-1 69970L sheets 1 ,2, and 3 and D-173096L sheet 1) utilizes the preferred power source

(230 kV Bainbridge line) per the FNP procedures for~restoring Unit 1 and 2 offsite power

following a wide-area blackout. Switchyard circuit breakers 840, 934, 924, and 904 represent

the first isolation device upstream from the startup transformers and demarcate the FNP SBO

recovery path from the transmission system.- This'path allows for the restoration for all four,

startup transformers once the preferred 230 kVsource is restored. Breakers 830, 820, and 800

could provide a direct path to individual transmission lines, but the use of these breakers would

require restoration of multiple transmission lines before all four startup transformers could be

powered. The 4.16 kV safety buses receive their power from one of the two secondary -

windings for each startup transformer, as shown on D-173096L. A nonsegregated cable bus

duct system provides the path between the startup transformers and the 4.16 kV safety buses.

The applicant has included the plant system portion of the offsite power system that is used to

connect the plant to the offsite power source in the scope of the Rule. This path includes (1)

the switchyard circuit breakers that are utilized to recover the offsite power source from the

transmission system (per plant ac power restoration procedure) that connects directly to the

startup transformers, (2) the transformers themselves, (3) the intervening overhead or

underground circuits between the circuit breaker and the transformer and between the

transformer and the onsite electrical distribution system, and (4) the associated control wiring.

Based on this information, the staff concludes that the applicant did not omit the SBO recovery

path at FNP.

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 that the applicant has adequately

identified the electrical and l&C systems components that are subject to an AMR, in accordance

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

2.6 Conclusion for Scoping and Screening

The staff has reviewed the information in Section 2, "Structures and Components Subject to

Aging Management Review," of the LRA. The staff determined 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, was consistent with the requirements of 10 CFR 54.21 (a)(1) and the staff's

position on the treatment of safety and nonsafety-related SSCs. On the basis of its review, the

staff concludes that the applicant's methodology for identifying the SSCs within the scope of

license renewal and the structures and components requiring an AMR is consistent with the

requirements of 10 CFR 54.4'and 10 CFR 54.21 (a)(1).

In addition to reviewing Section 2 of the LRA, the staff reviewed the accompanying scoping

boundary drawings to determine whether the applicant had omitted any SSCs that should be

within the scope of license renewal. The staff did not identify any omissions. Also, the staff

performed an independent assessment to determine if the applicant had identified all

components that should be subject to an AMR. The staff found no omissions. On the basis of

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its review, the staff concludes that the applicant has adequately identified those systems and

components that are within the scope of license renewal, as required by-10 CFR 54.4(a), and

that the applicant has adequately identified those systems and components that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

With regard to these matters, the NRC staff has concluded that there is reasonable assurance

that the activities authorized by the renewed licenses will continue to be conducted in -

accordance with the current licensing basis, and that any changes made to the FNP current

licensing basis in order to comply with 10 CFR 54.29(a) are in accord with the Act and the

Commission's regulations.

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3. AGING MANAGEMENT REVIEW RESULTS

This section of the safety evaluation report (SER) for the Joseph M. Farley Nuclear Plant (FN P),

Units 1. and 2, describes the U.S. Nuclear Regulatory Commission`(NRC) staff's (the sthff)

evaluation of the Southem Nuclear Operating Company, Inc.'s (SNC'or the applicant) aging;

management programs (AMPs) and aging management reviews (AMRs). In Appendix B to the

LRA, the applicant describes the 21 AMPs that it relies on to manage or monitor the aging of

long-lived, passive components and structures. By letter dated June 4, 2004, the applicant

supplemented the program discussions in Appendix B to the license renewal application (LRA)

by providing a new AMP, Section B.5.9, "Periodic Surveillance and Preventive Maintenanc&

Activities," which was not in the original application. In Section 3 of the LRA, the applicant -

provided the results of the AMRs for those structures and components (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 (GALL) Report

In preparing its LRA, SNC credited NUREG-1801,-,"Generic Aging Lessons Learned (GALL)

Report," dated July 2001. The GALL Report contains the staff's generic evaluation of the

existing plant programs and documents the technical basis for determining if existing programs

are adequate without modification or, if they should be augmented for the period of extended . operation. The evaluation results documented in the GALL Report indicate that many of the

existing programs are adequate to manage the aging effects for particular structures or

components 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 tothose reviewed and approved in the report. .-

The purpose of the GALL Report is to provide the staff with a summary of staff-approved AMPs

to manage or monitor the aging of 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 andeffectiveness 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) systems, structures, and components (SSCs), (2) SC 'materials,

(3) the environments to which the SCs are exposed, (4) the aging effects associated with the

materials and environments, (5) the AMPs that are credited with managing or monitoring the

aging effects, and (6) recommendations for further applicant evaluations of aging management

for certain component types. -

To determine whether using the GALL Report would improve the efficiency of the license '. renewal review, the staff conducted a demonstration project to exercise the GALL process and

to determine the format and content of a safety evaluation (SE) based on this pr6cess. .Th'e'

results of the demonstration project confirmed that the GALL process will improvelthe efficiency

and effectiveness of the LRA review, while maintaining the staff's focus on public health and

safety. NUREG-1 800, "Standard Review Plan for the Review of License Renewal Applications,"

dated April 2001 (SRP-LR), is based on both the GALL Report model and the less6ns'learned

-3-1
from the demonstration project.

The staff performed its work in accordance with the requirements of Title 10, Part 54, of the

Code of Federal Regulations (10 CFR Part 54), "Requiremnents for Renewal of OperatingLicenses for Nuclear Power Plants," the guidance provided in NUREG-1 800, the guidance

provided in NUREG-1 801, and the "Audit and' Review Plan for Plant Aging Management

Reviews and Programs,'Joseph M. Farley Nuclear Plant, Units 1 and 2," dated April 29, 2004

(ML042540243).

3.0.1 Format of the License Renewal Application

The SNC submitted an application that followed the standard LRA format, as agreed to by the

NRC staff and the Nuclear Energy Instifute (NEI) (see letter dated April7,_ 2003,

ML030990052). This revised LRA format incorporates lessons lea'rned from' the staff's review

of five previous LRAs submitted using a format developed from information gained during an

NRC staff and NEI demonstrati6n project.

The organization of Section 3 of the LRA parallels Chapter 3 of NUREG-1 800. The AMR

results discussed in Section 3 of the LRA are presented in the following two types of tables:

(1) Table 1. Table 3.x.1-where "3" indicates the LRA section number, "x" indicates the

subsection number from the GALL Report, and "1" indicates that this is the first table of

this type in Section 3 of the LRA.

(2) Table 2. Table 3.x.2-y-where "3" indicates the LRA'section number, "x" indicates the

subsection number of the GALL Report, "2" indicates thatthis is the second table of this

type in Section 3 of the LRA, and "y" indicates the system table number.

The content of the Orevious application's and the FNP application is essentially the same. The

revised format used for the FNP a~p1liation'modifies the tables in Section 3 to provide- . -- -

additional information to assist the staff in its review; In Table 1, the applicant summarized the

portions of the application it cornsiddred to be consistent with the GALL' Report. In Table 2, the

applicant identified the linkage between the scoping and screening results detailed in Section 2

of the LRA and the AMRs identified in Section 3 of the LRA.

3.0.1.1 Overview of Table 1

Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the

corresponding tables of the GALL Report, Volum e 1:.- The table is essentially the same as

Tables 1 through 6 in the GALL Report, Volume 1, except that the Type column has been

replaced by an Item Number column, and the Item Number in GALL column has been replaced

by a Discussion column. The Item Number column provides the reviewer with a means to

cross-reference Table 2 to Table 1. The applicant used the Discussion column to provide

'clrifying/amplifyihg information. The following are examples of information that might be

contained within this column:'

* further evaluation recommended-L-information or reference to where that information is

located

3-2
* the name of a plant-specific program being used

* exceptions to the GALL Report assumptions

* discussion of how the line is consistent with the corresponding line item in the GALL

Report, when that correspondence imay not be intuitively obvious

* discussion of how tthe item differs from' the corresponding line item in the GALL Report

(e.g., when there is exception taken to 'a'GALL AMP)

The format of Table i 'allows the staff to ali n a'secific Table 1 row'with the corresponding

table row in GALL, Volume 1, so that consistency can be confirmed easily.

3.0.1.2 Overview of Table 2

Table 3.x.2-y (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 (e.g., reactor coolant systems, engineered

safety features, auxiliary systems, etc.); For examrple, the engineered safety features group

contains tables specific to the containment spray system, containment isolation system, and

emergency core cooling system. Table 2 c'onsistsbf the following nine columns:

(1) Component Type. The first column identifies the component types from Section 2 of the

LRA that are subject to AMR. -The 66mponent types are listed in alphabetical order.

(2) Intended Function. The second column identifies the license renewal'intended functions

(including abbreviations where applicable) for the listed component types. The intended

functions table in LRA Section 2'provides the definitions and abbreviations of intended

functions.

(3) Material. The third column lists the particular materials of construction for the

component type.

(4) Environment The fourth column lists'the environment to which' the component types are

exposed. Int6rnal and extermal servic'ee'nvironments are inrdicated,'and the Internal

Service Environmients and Externil Service' Environments tables of LRA Section 3

provide a list of these 6'nvironrieinits.':

(5) Aging Effect Requiring Management. The fifth column lists aging effects requiring

management (AERMs). As part of the AMR process, the applicant determined any

AERM for each material-erivironmefit c6mbination. '

(6) Aging Management Pro6rams.' The sixth column lists the AMPs the applicant used to'

manage the identified aging effects:

(7) GALL Volume 2 Item. The seventh column lists the GALL Report item that the applicant

as similar to theAMR'results -identified 'p'resented in its LRA. The applicant compared

each combination of component type, material, environment, AERM, and AMP in Table

3-3
I M

2 of the LRA to the items in the GALL Report. If the GALL Report did not have a

corresponding item, 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 tables in the

GALL Report.

(8) Table 1 Item. The eighth column lists the corresponding summary item number from

LRA Table 1. If the applicant identified AMR results in Table 2 that are consistent with

the GALL Report, then the associated Table 3.x.1 line summary item number is listed in

Table 2. If there is no corresponding item in the GALL Report, then column 8 is left

blank. This allows the information from the two tables to be correlated.

(9) Notes. The ninth column lists the corresponding notes that the applicant used to identify

how the information in Table 2 aligns with the information in the GALL Report. The

notes identified by letters were developed by an NEI workinig group and will be used in

future LRAs. Plant-specific notes are identified by a number and provide additional

information concerning the consistency of the line item with the GALL Report.

3.0.2 The Staff's Review Process

The staff conducted the following three types of evaluations of the AMRs and associated AMPs:

(1) For items the applicant stated were consistent with the GALL Report, the staff audited

the applicant's technical justifications for consistency.

(2) For items the applicant stated were consistent with the GALL Report with exceptions,

the staff conducted an audit of the item and of the applicant's technical justification for

the exceptions.

(3) For other items, the staff conducted a technical review.

The staff performed onsite audits and technical reviews of the license renewal applicant's AMPs

and AMRs for evaluation types (1) and (2) above. Details of the staff's the audit and review are

documented in the 'Audit and Review Report for Plant Aging Management Reviews and

Programs, Joseph M. Farley Nuclear Plant, Units 1 and 2 (FNP Audit and Review Report),"

dated September 10, 2004 (ML042540277). The onsite audits and reviews were performed

from November 3 to November 7, 2003; December 15 to December 19,2003; and February 24

to February 26, 2004, to determine whether the AMPs and the AMR results that the applicant

claimed were consistent with the GALL Report were actually consistent.

3.0.2.1 Review of AMPs

For those AMPs for which the applicant claimed consistency with the GALL AMPs, the staff

conducted an AMP audit to determine whether the applicant's claim is consistent as claimed.

For each AMP that had one or more deviations, the staff evaluated each deviation to determine

(1) whether the deviation was acceptable, and (2) whether the AMP, as modified, would

adequately manage the aging effects for which it was credited.

For AMPs that the applicant claimed were plant-specific or were not evaluated in the GALL

3-4
Report, 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) Scone of Program. s&6jp eThe of 'program should include the'specific SCs subject to an

AMR for license renewal.

(2) Preventive Actions. Preventive actions should prevent or mitigate aging degradation'.

(3) Parameters Monitored or Inspected.' The parameters monitored or inspected should be

linked to the degradation of the particular structure or component intended functions.

(4) - Detection of Aging Effects. D6te6tion of aging effects should occur before there is a

loss of structure or component intended functi6ns.' This includes'aspects such as"

method or te6hnique (i.e., visual,"volumetric, surface inspection), frequency, sample

size, data 66llection, and timing of nbw/onetim& inspections to ensure timely detection

of aging effects.'

(5) Monitoring and Trending. Monitoring and trebding should provide predictability of the

extent of degradation and timely corrective or mitigative actions.

(6) Acceptance Criteria. The acceptance criteria, against which the need for corrective

'action is evaluated, should ensure that the structure or component intended functions'

- are maintained'under all CLB'design conditions during the period of extended operation.

(7) :Corrective Actions. Corrective actions,'including root cause determination and

prevention of recurrence, should be timely.

(8) Confirmation Process.' The confirmation process should ensure that preventive actions

are adequate and that appropriate corrective actions have been completed and are

'effective. - - - -

(9) Administrative Controls. Adrministrative'controls'should provide'a'formal reviewand

---approval process. -

(10) Qoerating Experience. The operating experience of the AMP, including past corrective

actions resulting in program enharncements or additional programs, should provide

objective evidence' to support therconclusiori that the effects of aging will be managed

adequately so that the structure and component intended functions will be maintained

during the period of extended operation.

The staff reviewed the applicant's Corrective Action'Program and documented its findings in

Section 3.0.4 of this SER.- The staff's evaluation of the Corrective Action Program included

assessment of the Corrective Actions; Confirmation Process, and Administrative Controls

program elements. Consequently,,the'staff's documentation of its review of AMPs not

consistent with the-GALL Report only addresses 7 of the 10 program elements under Staff

Evaluation sections of this SER in Sections 3.1 through 3.6.

The staff reviewed the information concerning the Operating Experience program element for

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I

the AMPs that are consistent with the GALL report, and documented its findings in the FNP

Audit and Review Report.

The staff reviewed the final safety analysis review (FSAR) Supplement for each AMP to

determine if it provided an adequate description of the program or activity, as required by 10

CFR 54.21 (d).

3.0.2.2 Review of AMR Results

Table 2 includes all of the AMR information pertaining to FNP, Units 1 and 2, whether or not it

aligns with the AMR information identified in the GALL Report. For a given AMR listed in Table

2, the staff reviewed the intended function, material, environment, AERM, and AMP

combination for a particular component type within a system. TheAMRs that correlate between

a combination in Table 2 and a combination in the GALL Report were identified by a referenced

item number in column 7, GALL Volume 2 Item. -The staff conducted an audit to evaluate the

correlation. A blank column 7 indicates that the applicant was unable to locate an appropriate

corresponding combination in the GALL Report. The staff conducted a technical review of

those combinations that were not consistent with the GALL Report. Column 8, Table 1 Item,

provides a reference number that indicates the corresponding row in Table 1.

3.0.3 Aging Management Programs

The following Table 3.0.3-1 presents the AMPs credited by the applicant and described in

Appendix B to the LRA. The table lists its AMP (if applicable) that the applicant has claimed is

consistent with the GALL program, and the SSCs that credit the AMP for managing or

monitoring aging. The table also provides the respective section of the SER in which the staff's

evaluation of the program is documented.

Table 3.0.371 FNP Aging Management Programs

FNPAMP GALL: GALL I LRA Systems or Structures, Staffs

(LRA Secton) Comparison' AMP(s) That Credit the AMP |' SER Section

Existing AMPs (B.3.0) :

Inservice Inspection Consistent XI.M1 Reactor Vessel, Internals, 3.0.3.1

Program (B.3.1) XI.M3 and Reactor Coolant System; Xl.M12 Containments, Structures, XI.S1 and Component Supports

Xl S2

XL.S3

XI.S4

Water Chemistry Consistent with XI.M2 Reactor Vessel, Intemals, 3.0.3.2.1

Control Program one exception XI.M21 and Reactor Coolant System; (B.3.2) Engineered Safety Features

Systems;

Auxiliary Systems; Steam and Power

Conversion Systems; Containments, Structures,

and Component Supports

3-6
FNP AMP GALL - - --GALL> LRA Systems or Structures -- Staff's

: (LRA Section) . Comparison . AMP(s -: -- That Credit the AMP: .:SER Section !

Service Water Pond Consistent XI.S7 Containments, Structures, 3.0.3.1

Dam Inspection and Component Supports

Program (B.3.3). _ _ . . _

Reactor Vessel Consistent with XI.M31 Reactor Vessel, Internals, 3.0.3.2.2

Surveillance Program one exception and Reactor Coolant System

(B.3.4) _ _ _ _ i

Borated Water Consistent XI.M10 Reactor Vessel, Internals, 3.0.3.1.1

Leakage Assessment . and Reactor Coolant System;

and Evaluation , . Engineered Safety Features

Program (B.3.5) . Systems; -

Auxiliary Systems;

Steam and Power

C6nversion Systems; .

Containments, Structures,

iand Component Supports

Overhead and Consistent Xl.M23 Auxiliary Systems 3.0.3.1

Refueling Crane

Inspection Program

(B.3.6) _ - -___. -

Environmental Consistent Xl.EJ Electrical Components 3.0.3.1 -

Qualification

Program (8.3.7) _ . :

Steam Generator, Consistent XI.M19 Reactor Vessel, Intemals, 3.0.3.1.2

Program (B.3.8) and Reactor Coolant System

Enhanced AMPs (B.4.) .

Flow-Accelerated Consistent with XI.M17 -Steam and Power 3.0.3.2.9

Corrosion Program enhancement . Conversion Systems

(B.4.1) . . ..

Fuel Oil Chemistry Consistent with XM.M30 Auxiliary Systems 3.0.3.2.3

Control Program exception and

(8.4.2) enhancement.. ...

Structural Monitoring Consistent with XI.S5 Containments, Structures, 3.0.3.2.4

Program (B.4.3)- *- enhancement XI.S6 -. . and Component Supports,

._-_._____._._ I Auxiliary Systems .

Service Water Consistent with XI.M20 Auxiliary Systems; 3.0.3.2.5

Program (B.4.4) -- -enhancement - -_ Steam and Power-. .. .

:Conversion Systems

Fire Protection Consistent with .. XI.M26 Auxiliary Systems; 3.0.3.2.6;

Program (B.4.5) enhancements XI.M27 Containments, Structures,

and Component Supports

New AMPs (B.5.0)

Reactor Vessel Consistent with Xi.M13 -. Reactor Vessel, Internals, 3.0.3.2.7

Internals Program exceptions X1.M16, J and Reactor Coolant System
II

FNPAMP GALL * GALL' LRA Systemsii or Structures Staff'sr:--

(LRA Sectlon, -~ Comparison - AMP(s) - --. That Credit the AMP .-. SER'SectionFlux Detector Plant specific N/A Reactor Vessel, Internals, 3.0.3.3.1

Thimble Inspection and Reactor Coolant System

Program (B.5.2)

External Surface Plant specific N/A Engineered Safety Features 3.0.3.3.2

Monitoring Program Systems;

(B.5.3) Auxiliary Systems;

Steam and Power

Conversion Systems;

Electrical Components

Buried Piping and Consistent with XI.M34 Auxiliary Systems; Electrical 3.0.3.2.10

Tank Inspection exceptions Components

Program (B.5.4)

One-Time Inspection Consistent XI.M32 Reactor Vessel, Internals, 3.0.3.1

Program (B.5.5) XI.M33 and Reactor Coolant System;

Engineered Safety Features

Systems;

Auxiliary Systems;

Steam and Power

Conversion Systems

Non-EQ Cables

Program (B.5.6):

(1) Non-EQ Electrical 1) Consistent XI.E2 Electrical Components 3.0.3.2.8

Cables Used in with one

Instrumentation exception

Circuits ( B.5.6.1) .

(2) Non-EQ Electrical 2) Consistent XI.E1 Electrical Components 3.0.3.1

Cables Exposed to XI.E3

Adverse Localized

Environments and

Inaccessible Medium

Voltage Cables

(B.5.6.2)

Fatigue Monitoring Consistent X.M1 Reactor Vessel, Internals, 3.0.3.1

Program (B.5.7) and Reactor Coolant System

NiCrFe Component Plant specific N/A Reactor Vessel, Internals, 3.0.3.3.3

Assessment Program and Reactor Coolant System

(B.5.8)

Periodic Surveillance Plant specific N/A Auxiliary Systems; Steam 3.0.3.3.4

and Preventive and Power Conversion

Maintenance Systems

Activities Program

(B.5.9) .

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:

3-8
* Inservice Inspection Program (B.3.1)

* Service Water Pond Dam Inspection Program (B.3.3)

* Borated Water Leakage Assessment and Evaluation Program (B.3.5)

* Overhead and Refueling Crane Inspection Program (B.3.6)

* Environmental Qualification Program (B.3.7)

* ' Steam Generator Program (B.3.8)

* One-Time Inspection Program (B.5.5)

* Non-EQ Electrical Cables Exposed to Adverse Localized Environments and Inaccessible

Medium Voltage Cables (B.5.6.2)

* Fatigue Monitoring Program (B.5.7)

During its audit conducted November 3 to November 7, 2003, the staff reviewed selected

documents and procedures associated with'the AMPs that are listed above. The staff

confirmed the applicant's claim of consistency. The FNP Audit and Review Report documents

details of the staff's evaluation of the`FNP a"udit 6and review. The staff determ ined that these

AMPs are consistent with the AMPs described in the GALL Report.

The staff reviewed the operating experience associated with the AMPs that are listed above.

With the exception of its review of the industry' expe'rience applicable to the applicant's"

implementation of the Borated Water Leakage Assessment and Evaluation and Steam .

Generator Programs, the staff concludes that the applicant adequately considered the

operating experience associated with the AMPs.

The Borated Water Leakage Assessmentiand Evaluation Program, as discussed in Section

B.3.5 of Appendix B to the FNP LRA, is based on the applicant's response to NRC Generic"

Letter (GL) 88-05, 'Boric Acid Corrosion of Steel Reactor Pressure Boundary Components in

PWR Plants," dated May 31, 1988. However, a supplemental evaluation was necessary

because recent, additional borated water leakag'e events have occurred in'the industry'that are

relevant to the scope and implementation of this AMP. Section 3.0.3.1.1 of this SER provides

the staff's supplemental evaluation of the Bo1rated Water Leakage Assessment and Evaluation

Program. .

The Steam Generator Program, as discussed in Section B.3.8 of Appendix B to the FNP LRA,,

is based on the applicant's inspection program for steam generator (SG) tubes, as'defined in

the improved technical specifications (TS) for FNP,'Units 1 and 2, and enhanced to conform to

the inspection guidelines of NEI 97-06, uSteam'Generator Program Guidelirieg," issued in 1997.

The supplemental evaluation in Section 3.0.3.'.21of this SER discusses how the program -

attributes for the Steam Generator Program address its conformance with the guidelines of NEI

97-06.

In Appendix A to the LRA, the applicant provided the FSAR Supplement required by 10 CFR

54.21 (d). The applicant stated that it will inco6rporate the information 'presented in Appendix A.

into Chapter 18 of the FSAR, following the issuance of the renewed operating licenses. The

staff reviewed the' inf6rmation in Appendix A and'evaluated that the FSAR Supplement provides

an adequate summary of the programn activities.-Thebstaff reviewed the following sections of

Appendix A to the LRA: ' - -' --

* Section A.2.1 of the LRA for the Inservice Inspection Program . J3-9
I Io

0 Section A.2.3 of the LRA for the Service Water Pond Dam Inspection Program

* Section A.2.5 of the LRA for the Borated Water Leakage Assessment and Evaluation

Program

* Section A.2.6 of the LRA for the Overhead Heavy and Refueling Crane Inspection

Program

* Section A.2.7 of the LRA for the Steam Generator Program

* Section A.2.17 of the LRA for the One-Time Inspection Program

* Section A.2.19 of the LRA for Non-EQ Cables Program

* Section A.3.1 of the LRA for the Environmental Qualification Program

* Section A.3.2 of the LRA for the Fatigue Monitoring Program

The staff reviewed these sections and determined that the information in the FSAR

Supplements provides an adequate summary of the program activities. The staff finds these

sections of the FSAR Supplements sufficient.

On the basis of its audit and review, the staff concluded 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 FNP Audit and Review Report documents the details of the

staff's evaluation of the FNP audit and review.

3.0.3.1.1 Borated Water Leakage Assessment and Evaluation Program

Summary of Technical Information in the Application

The applicant summarized the Borated Water Leakage Assessment and Evaluation Program in

Section B.3.5 of Appendix B to the FNP LRA. In Section B.3.5 of the LRA, the applicant stated

that the AMP is used to manage loss of material in areas where carbon steel or low-alloy steel

components may be susceptible to the effects of borated reactor coolant leaks. The applicant

stated that this AMP is implemented in accordance with plant-specific commitments made in

response to GL 88-05, and that it has given special attention to areas where insulated Class 1

bolted closures are located.

Staff Evaluation

Scope of the Program and Detection of Aging Effects

The applicant stated that the Borated Water Leakage Assessment and Evaluation Program is

based on the applicant's response to GL 88-05, and that the AMP is entirely consistent with the

program attributes of GALL AMP XI.M1 0, uBoric Acid Corrosion," without exception. The staff

included the applicant's response to GL 88-05 within the scope of its review of this AMP.

In its response to GL 88-05, the applicant stated that it had a current plant-specific program at

3-10
FNP for the identification, evaluation, arid orrectiodri of leaks that could potentially occur in plant

systems containing boric acid. This pr6gramr' (henc6forth termed the GL 88-05 program) is the

basis for the applicant's Borated Water LbakageAssessment'dnd Evaluation Program

discussed in Section B.3.5 of theLRA and corisists'o'f, as appropriate; inspections, evaluations,

repairs, reviews of industry experience, and corrective actions, should leakage be detected. In

its response to GL 88-05, the applicant also id6_ntified that the following welded connections arid

mechanical connections could be subje6t to leaka~ge:,

* reactor vessel head penetration canopy seal welds

* full-penetration welds on ASME Code Class 1 and 2 components

* 'i'pressurizer heater penetration welds d -

* manway covers

* reactor coolant pump main flange

* reactor coolant pump seal housing-' ----- - * reactor vessel flange

* reactor vessel conoseal bolting

* valve body-to-bonnet connections' '- ;

valve packing

flanged connections

*~ resistance temperature detectors -

NRC Bulletins (BLs) 2002-01,'"Reactor Pressure Vessel Head Degradation and Reactor

Coolant Pressure Boundary Integrity," dated March'18,2002,'and 2003-02 and NRC Order EA03-009 (both the original version and Revision I of the Order)document industry experience

reported in American Society of Mechanical Engineers (ASME) Code Class 1 nickel-alloy,

partial-penetration welds, including those 'used to join the upper -reactor vessel (RV) head

penetration nozzles to the upper RV heads and those us6d to join the bottom-mounted

instrumentation (BMI) nozzles to the lower RV heads of pressurized-water reactors (PWRs).

The staff requested additional clarification regarding the list of components that are within the

scope of the Borated Water Leakage As~dsim-eht and Evaluation Program and the process the

applicant uses to augment the list of in-scope components based on pertinent industry

experience. Specifically, the staff requested the following actions of the applicant:

* -Submit the list of component locations that are currently within the scope of the Borated

Water Leakage Assessment arid Evaluation Program and a discussion of the process

used to augment ASME Code Class 1-and 2 component locations within the scope of

the AMP, based on relevant industry experience.

* Discuss how SNC's responses to NRC BL 2002-01, dated March 29, 2002, and May 16,

-2002; responses to the NRC's requests for, additional information (RAIs) on the bulletin,

dated January 17, 2003; response to NRC BL2003-02, dated September 19,'2003; and

responses to NRC 'Order EA-03-009, 'dated March 3, 2003, April 11,2003, and April 18,

2003, have been' used to update the list'of component locations'and types'of visual

- inspections credited within the scope of the'Borated Water Leakage Assessment and

Evaluation'Program or within'the scope of other AMPs that provide for similar or more

conservative types'bf inspections. ': '" '- -

* If the responses were used to supplemrent the scope of the Borated Water Leakage

Assessment and Evaluation Program or other AMPs, identify the component locations

'3-11
1'

that have been added to the scope of the program and clarify the type of visual

- examinations (i.e., specify whether VT-1, VT-2 or VT-3 will be used and whether the

visual examinations will be enhanced, bare-surface, qualified, etc.) that will be

implemented on those components within the current scope of the program.

The staff identified these issues as within the scope of RAI, B.3.5-1 (refer to NRC RAI dated

March 17, 2004). The staff's evaluation of the Operating Experience program attribute further

discusses the operating experience relevant to the Borated Water Leakage Assessment and

Evaluation Program.

The applicant provided the following response to RAI B.3.5-1 in its letter dated April 16, 2004

(SNC Letter No. NL-04-0617):

SNC's responses to the referenced NRC documents (bulletins and executive order) did not change

component locations inspected under the Borated Water Leakage Assessment and Evaluation Program

(BWLAEP) but did result in changes in inspection activities and leakage detection methods.

The FNP responses to NRC Bulletins 2002-01 and 2002-02 provided summary information on the reactor,

pressure vessel (RPV) head inspections and maintenance activities at Plant Farley and information on the

inspections performed at Alloy 600 and dissimilar metal Alloy 82/182 weld locations in the reactor coolant

pressure boundary (RCPB). The FNP response to NRC Bulletin 2003-02 described inspection procedures, inspection results, and future plans for the inspection of RPV lower head penetrations and other Alloy 600

and Alloy 82/182 weld locations. These responses contained new, specific commitments (discussed in the

following paragraphs) relative to RPV upper (top) and lower head examinations and reactor coolant

pressure boundary leakage detection that are incorporated into the BWLAEP.

FNP committed to perform a semi-annual sample and analysis of the containment atmosphere for ironconcentration as a measure to assist In the detection of low levels of RCS leakage. FNP also committed to

perform a best effort visual examination of the metal surface under the insulation of the RPV bottom head

during the next refueling outage at each unit (U1R18 during Spring 2003 and U2R16 during Spring 2004). As stated in our response to NRC Bulletin 2003-02, the RPV bottom head inspections are a direct visual

aided by remote devices and meet the intent of the MRP recommendations described in MRP 2003-017.

The qualification standards for the visual examination procedures require resolution of the 0.105 inch lowercase character height which was taken from the EPRI Head Penetration report as applicable for lower head

penetrations and has been the standard since the 1992 Edition of ASME for VT-3 examinations. The

schedule and extent of subsequent inspections of the RPV bottom head will be determined pending results

of the visual examinations of the outer surface of the bottom head, the results of the root cause analysis of

the bottom-mounted instrumentation at South Texas Project Unit 1, and future industry experience.

For the RPV top heads, FNP had committed to implementing the Electric Power Research Institute (EPRI) Materials Reliability Program (MRP) Inspection Plan on the existing RPV heads in addition' to the existing ASME Section Xl inspection requirements. Subsequently, the NRC has issued mandatory RPV head

inspection requirements (Revised NRC Order EA-03-009) that now govern RPV top head inspections.

Revised NRC Order EA-03-009 has established requirements for reactor pressure vessel (RPV) head

penetration inspections that assign a susceptibility category to each RPV head related to PWSCC

degradation. FNP has committed to" replace the RPV upper heads prior to the period of extended operation

(Ul is scheduled for Fall 2004 and U2 in Fall 2005), utilizing thermally-treated Alloy 690 based metal and

Alloy 52/152 weld base metal for all closure head penetrations. Although the original FNP upper RPV

heads fall into the" high" susceptibility category, the replacement RPV upper heads will fall into the

Ureplaced' susceptibility category. Therefore, inspection requirements for the uppe'r RPV heads'will be

reduced prior to FNP entering into the period of extended operation based on Revised NRC Order EA-03-

009. Based on Paragraph IV.C(4) of the Revised NRC Order February 20, 2004 for the,"replaced' RPV

head category, no RPV head or head penetration nozzle inspections would be required during the refueling

outage for which the RPV head was replaced. After that time, until the effective degradation year (EDY) value reaches eight, the reduced inspection requirements consist of the following:

3-12
(i) A bare metal visual examination of 100% of the RPV head surface, Including 360 degrees

around each RPV head penetration nozzle every third refueling outage or five years

whichever comes first, and.. .

*(ii) Anonvisual NDE (ultrasonic; eddy current or dye penetrant tests) for each penetration

every fourth refueling outage or seven years whichever comes first.: ., * . . .. . ,.. - ; .; - .- ; -,

Currently,- FNP is considered a 'high" susceptibility plant that requires performance of the above inspections

every refueling outage. - .. .

The applicaant's response to RAI B.3.5-1 dated Apri :16,2004 (SNC Letter No. NL-04-0617)

accomplishes three important aspects of tlhe process used to augment the Borated Water

Leakage Assessment and Evaluation Program:

(1) The response provides a detailed 'discu'sion that clarifies how the applicant applied pertinent industry boric acid leakage experience to modify the Program Scope and other

program attributes for' the Borated Water Leakage Assess ent and Evaluation

Program. . - -

(2) The response confirms that th'e applicant has applied the industry experience .

summarized in NRC BLs 2002-01 and'2003-02 and NRC Order EA-03-009 to augment

the inspection methods used for examining and monitoring for degradation and reactor

coolant leakage from penetration nozzles adjoined to the FNP upper and lower RV

heads.. ' : .

(3) The response clarifies that the applicant considers nickel-alloy components (i.e., nickelchromium-iron (NiCrFe)) to be susceptible locations and included them within the scope

of the Borated Water Leakage Assessm'ernt and Evaluation Program.

Because the applicant's 'response to RAI B.3.5-1 (1) clarifies how the applicant has applied

pertinent industry experience to augment the scope of components within the Borated Water

Leakage Assessmentiand Evaluation Prog'ramc '(2) clarifies that nickel-alloy component

locations are within' the scope of the AMP, and (3)'clarifies how the applicant has augmented

the types'of visual examiniation methods it uses for monitoring leakage from the upper and

lower RV head penetration nozzles, the staff concludes that the applicant's' response to RAI

8.3.5-1 is acceptable.' RAI B.3.5.-i is resolved.-'

Preventive Actions. Parameters Monitored/lrnsected, Detection of Aging Effects. Monitoringi

and Trendiria.and Acceptance Criteria '

The applicant's discussion in AMP B.3.5 indicates that it considers the Preventive Actions,

Parameters Monitor6dllnspected, Detection of 'Aging Effects, Monitbrinig and Trending,'and

Acceptance Criteria to be'consistent with' th corresponding program attributes in GALL AMP

XI.M1 0, `BoricdAcid CorroIsion," without exception or deviation. Because the' Pr6ventive

Actions', Parameters Monitored/lInspecte'd,' Detectio.6 of Aging Effects, Monitoring and Trending,

and Acceptance Criteria p-rogram attributes for the Bdrated Water Leakage Assessment and

Evaluation Program are consistent with the recommendations in the corresponding program

attributes of GALL AMP XI.M10,'the staff concludes that these program attributes forthe

Borated Water Leakage Assessment a6rid Evaluatiorn Program are acceptable.'

t -o at . a . . , :- -- t ,- -. _<,

3-13
Operating Experience

Significant industry experience exists that is relevant to the scope of the applicant's Borated

Water Leakage Assessment and Evaluation Program. NUREG/CR-5576, uSurvey of Boric Acid

Corrosion of Carbon Steel Components in Nuclear Plants," dated January 1990, summarizes

boric acid leakage and corrosion events that occurred in the industry before 1990. More

recently, industry experience (refer to the operating events summarized in NRC BL 2002-01,

NRC Executive Order EA-03-009, and NRC Regulatory Information Summary (RIS) 2003-13)

has demonstrated that the nickel-alloy partial-penetration welds (Alloy 82/182 welds) used in

the fabrication of upper RV head penetration nozzles may be susceptible to primary water

stress-corrosion cracking (PWSCC) that could lead to leakage of the' borated reactor coolant

over time. In addition, the industry experience summarized in NRC BL 2003-02 demonstrates

that the BMI nozzles of PWR-designed, light-water reactors may be susceptible to PWSCC that

co'uld lead to reactor coolant leakage. 'The staff included the applicant's responses to these

bulletins and the executive order within the scope of its review of the AMP and issued RAI

B.3.5-1 to address how the applicant incorporated this industry experience into the scope of the

Borated Water Leakage Assessment and Evaluation Program.. Since the issuance of RAI

B.3.5-1, industry experience summarized in NRC BL 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," dated May 28, 2004, demonstrates that Alloy 600

base metal and Alloy 82/182 Weld components used in pressurizer penetration nozzles and

steam space piping connections may be susceptible to PWSCC and reactor coolant leakage.

In issuing RAI B.3.5-1, the staff inquired as to the process the applicant would use to augment

the list of components within the scope of. the Borated Water Leakage Assessment and

Evaluation Program based on pertinent industry experience. This was done, in part, to account

for any industry experience on borated water leakage events that could possibly impact the

AMP between the time the applicant had responded to RAI B.3.5-1 in its letter dated April 16,

2004 (SNC Letter No. NL-04-0617) and the time-of the pending issuance of the renewed

operating licenses for the" FNP. units. Altho'ugh the applicant's response to RAI B.3.5-1 was

submitted before the staff issued NRC BL 2004-01, the applicant confirmed that it is updating

the list of components within the scope of the Borated Water Leakage Assessment and

Evaluation Program based on reactor coolant leakage events within the industry. Further, the

applicant has included ASME Code Class 1 Alloy 600 base metal and Alloy 82/182 weld

components within the scope of the Borated Water Leakage Assessment and Evaluation

Program. This includes any ASME Code Class 1 Alloy 600 base metal and Alloy 82/182 weld

metal components in the pressurizer system.

The staff and the industry are currently pursuing resolution of the issues raised and discussed

in NRC BL 2004-01 regarding PWSCC and reactor coolant leakage in pressurizer penetrations

and steam space piping connections. Because this is an emerging issue that has yet to be'

resolved, but will be during the current operating term for the FNP units, consideration of these

issues is beyond the scope of this license renewal review, pursuant to 10 CFR 54.30(b).

Based on this assessment, the staff concludes that the Operating Experience program attribute

is acceptable because the applicant is applying pertinent generic communications on borated

reactor coolant leakage e'vents as the basis for augmenting the scope of the Borated Water

Leakage Assessment and Evaluation Program. In addition, the applicant updated the Scope

program attribute for the Borated Water Leakage Assessment and Evaluation Program to

3-14
include ASME Code Class 1 Alloy'600 base metal and Alloy 82/182 weld metal components.

FSAR Supplemenit

The applicant provided the following FSAR Supplement summary description for the Borated

Water Leakage Assessment and Evaluatioh'Prograln-in Section A.2.5 of Appendix A to the

LRA:

The Borated Water Leakage Assessment and Evaluation program implements the plant-specific

commitments made in response to NRC Generic Letter 88-05. The program is applicable to areas

where there are carbon steel and low-alloy steel structures or components, or electrical

. components, on which borated reactor water might leak. This program is consistent with the 10

attributes of the aging management program described in NUREG-1801, Section XI.M1O.

The applicant's FSAR Supplement surnrmary description' for the Borated Water Leakage

Assessment and Evaluation Program providesta general reference to' commitments made in the

applicant's response to GL 88-05. The staff requested that the applicant amend the FSAR

Supplement summary description to provide'rriore specific references to its response to GL 88-

05 and to any additional responses to NRC generic communications (i.e., GLs, BLs, orders, or

circular letters) that are germane to the Scope or other program attributes for the AMP, or have

been used to amend the program attributes for the AMP, including those responses to NRC BL

2002-01 and 2003-02 and to NRC Order EA-03-009, as appropriate. The staff issued these

requests in' RAI B.3.5-2.

The applicant provided the following response to RAI B.3.5-2 in its letter dated April 16, 2004

(SNC Letter No. NL-04-0617)_

Providing specific references to FNP responses to NRC generic communications that are germane

to the Borated Water Leakage Assessment and Evaluation Program (BWLAEP) would be unwieldy

and inconsistent with the level-of-detail presented in'th6 FSAR, and Is unnecessary. The FNP-'

specific responses to NRC communications are'readily retrievable in the NRC Public Document

Room. References to applicable NRC generic communications are Incorporated into the program

governing documents as appropriate.

To address the NRC's concern, SNC will revise the FSAR Supplement description in Appendix

A.2.5, Borated Water Leakage Assessment and Evaluation Program as follows (changes Indicated

by bold Italics):

"The Borated Water Leakage Assessment and Evaluation program implements the plant-specific

commitments made in response to NRC Generic Letter 88-05 and subsequent NRC communications on

boric acid corrosion and leakage detection which Include NRC Bulletins 2001-01, 2002-01, 2002-02,

2003-02, and NRC Order EA-03-009 (as revised). The program is applicable to areas where there are

carbon steel and low-alloy steel structures or components, or electrical components, on which borated

reactor water might leak. ! -

This program Is consistent with the 10 attributes of the aging management program described in,

NUREG-1801, Section XI.M1O.' ;

The staff issued RAI B.3.5-2 to assure that the applicant's discussion in its FSAR Supplement

summary description for the Borated Water Leakage Assessment and Evaluation Program was

consistent with relevant NRC generic communications and the CLB for the plants. The

applicant's response to RAI 3.3.5-2 indicates that the applicant has amended the' FSAR

Supplement summar description for the'B6rated Water Leakage Assessment and Evaluation

*3-15
I

Program to include the applicant's responses and commitments made in reference to NRC BLs

2001-01, 2002-01, 2002-02, 2003-02, and NRC Order EA-03-009, as amended by the

applicant's response to the first revision of the Order. The staff concludes that the FSAR

Supplement summary description for the Borated Water Leakage Assessment and Evaluation

Program, as amended by the applicant's response to RAI B.3.5-2, is acceptable because the

summary description is current with the CLB for the facilities and references SNC's responses

and commitments to NRC generic communications that are relevant to the scope and

implementation of the AMP. RAI B.3.5-2 is closed.

Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that, for the

Borated Water Leakage Assessment and Evaluation Program, 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 reviewed

the associated FSAR Supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.2 Steam Generator Program

The applicant described its Steam Generator Program in Appendix B.3.8 to the LRA. This is an

existing program. The applicant stated that the program is based upon NEI 97-06, which

provides for detecting flaws in tubing and secondary-side internals degradation. The applicant

uses the program to perform SG surveillance in accordance with the TS. The applicant also

stated that its program is consistent with GALL AMP Section XI.M1 9 with no exceptions.

The staff reviewed the applicant's description of the program in Appendix B.3.8 to the LRA to

determine whether the applicant has demonstrated that the program will adequately manage

the applicable aging effects in the FNP's steam generators during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

Summary of Technical Information in the ADplication

The applicant replaced its original Westinghouse Model 51 steam generators with

Westinghouse Model 54F replacement SGs. The Units 1 and 2 replacement steam generators

were installed in May 2000 and May 2001, respectively. The applicant's replacement SGs

incorporate several improvements over the original Model 51 steam generators, including

thermally treated Alloy 690 tubes, stainless steel tube support plates, and stainless steel

antivibration bars. The applicant stated that the only indication of tube degradation of Alloy 690

thermally treated tubes has been wear related, either as a result of loose parts or at tube

support structures. The applicant further stated that it will update its Steam Generator Program

as required to incorporate changes to NEI 97-06 and the associated Electric Power Research

Institute (EPRI) guidelines for steam generators.

Staff Evaluation

The first inservice inspection (ISI) of the applicant's Unit 1 replacement SGs was conducted

during the U1 R16 outage in Fall 2001. The inspection consisted of 100 percent eddy current

testing (ECT), with a bobbin probe, of all inservice tubes over their full length in all three Unit 1

3-16
steam generators. A rotating pancake coil probe equipped with a PointTm probe was used to

inspect 100 percent of the low row (rows 1 and 2) U-bends, 20 per6ent of the hot-leg top-oftubesheet region, and all bobbin signals that indicated a change since the preservice inspection

or that were newlyfound during the U1 R16 outage.) The inspection detected no evidence of

axial or circ mrnferential crack-lik6 indications, wear, or service-induced reduction in wall - ;

thickneiss, and no' tubes-were plugged. The first ISl of the SGs in Unit 2 was scheduled for, ,-'.:

Spring 2004. 'The results of the inspection were consistent with those that have been observed

in other plantscduring their first ISI, namely that'wear was the only form of active degradation.

In Appendix B.3.8 to the LRA, the applicant stated that the Steam Generator Program is based

upon NEI 97-06, which includes an assessment of degradation mechanisms and considers.,

operating experience'from similar SGsto 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 associated with NEI

97-06 provide criteria for the qualification of personnel, specific techniques, and the associated

acquisition' &id 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.vA steam generator program,.as defined ini

NEI 97-06, includes guidance on assessing 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,-relieson

monitoring and control of reactor water chemistry and secondary water chemistry. The

applicant stated in Appendix B.3.8 that it will update its Steam Generator Program,-as required,

to incorporate changes to NEI 97-06 and the' EPRI guidelines for steam generators. -

In Appendix B.3.8'to the LRA, the applicant stated that the Steam Generator Program is

consistent with GALL AMP XL.M19, "Steam Generator Tube Integrity," which is an AMP credited

for managing the aging effects of the SG tubes and tube plugs.. GALL AMP XI.M19

recommends preventive measures for mitigation of degradation phenomena, assessment of

degradation mechanisms, conduct of inservice inspection of SG tubes to detect degradation,

evaluation and plugging or repair, and monitoring 'of leakage to maintain the structural and

leakage integrity of the pressure boundary.- The applicant credited the Steam Generator

Program to manage the aging effects of secondary-side internals, which are listed in LRA Table

3.1:2-4.' The applicant noted no deviationsior enhancements.- The staff was unclear as to how

the applicant manages the SG secondary-side'internals. By letter dated March 22, 2004, in RAI

3.1.2.4-5, the staff requested that the applicant confirm that the Steam Generator Program

contains the 10 elements in its plant-specific program for managing the aging effects of the

secondary-side intemals. - ; i' - r 1

In its response to RAI 3.1.2.4-5 dated April 22, 2004 (SNC Letter No. NL-04-0678), the

applicant responded that the scope of the Steam Generator Program includes activities to

detect degradation of SG components,-the failure of which could impa6t tubing integrity.

Hence, the applicant's Steam'Generatbr Program is'consistent with the guidelines of NEI 97-06

and GALLAMP X1.M.19. NEI 97-06 includes monitoring of secondary-side SG components if

their failure'could prevent the SG from fulfilling its intended safety-related function.. The -

applicant went on to list the secondary-side internals (also listed in LRA Table 3.1.2-4) for which

its program is credited for the management of degradation. The staff finds that the scope of the

applicant's Steam Generator Program is appropriate because it is credited with the ,

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II

management of the secondary-side internals.

With regard to the preventive actions in its program, the applicant stated that while the,

replacement SGs iriclude several design and materials improvements, they are not preventive

measures of the Steam Generator Program. Consistent with NEI 97-06 and GALL AMP

XI.M1 9, the applicant's Steam Generator Program relies upon water chemistry controls to

prevent or mitigate initiation of degradation mechanisms or reduce, the rate of degradation., The

applicant implements these primary- and secondary-side chemistry controls as part of the

Water Chemistry Control Program. The staff finds that this program is a condition or

performance monitoring program because it does not rely on preventive actions. Therefore, no

preventive actions are associated with this program.- In addition, the staff concludes that the

program relies on the Water Chemistry Control Program to prevent or mitigate the initiation of

or reduce the rate of degradation.

With regard to parameters monitored or inspected in its program, the applicant stated that the

Steam Generator Program includes inspection activities intended to detect degradation of the

secondary-side internals needed to maintain tubing integrity and accomplishment of the SG

intended safety-related functions. An assessment based upon SG design, potential

degradation mechanisms, and related FNP and industry operating experience is performed to

establish inspection requirements for secondary-side internals components. The resulting

inspection requirements are incorporated into the SG inspection plans. The staff concludes,

that because the'a'pplicant's program utilizes inspection activities which are based on factors

such as the design/construction of the replacement SGs, degradation mechanisms, and

industry operating experience, the Steam Generator Program will monitor the parameters

necessary to mitigate and prevent degradation-of the secondary-side internals.

With regard to the detection of aging effects by its program, the applicant stated that SG tubing

ECT data provide some indication of secondary-side conditions (e.g.,- evidence of loose parts).

However, detection of aging effects in the SG secondary-side internals is primarily

accomiplished through the use of visual inspections. The applicant considered industry and

FNP-specific operating experience' resulting from prior inspections and cleaning activities (e.g.,

sludge lancing, sludge collector cleaning, etc.) in establishing secondary-side inspection

requirements. Inspections of-SG secondary-side components are performed as needed to

assess conditions or evaluate potential degradation mechanisms. -Visual inspections are

adequate to detect loss of material and cracking of SG internal support structures before any

detrimental impact on tube integrity.- Various tools and techniques are available for visual

inspection of secondary-side components. The staff concludes that, because the applicant

conducts periodic visual inspections, eddy current inspections of the SG tubes, and variouscleaning activities, the Steam Generator Program will detect aging of secondary-side internals

before there is a loss of structure or intended component function.

With regard to monitoring and trending in its program, the applicant stated that, consistent with

NEI 97-06, secondary-side SG components, whose failure could prevent the SG from fulfilling

its intended safety-related function, shall be monitored. NEI 97-06 states, "The monitoring shall

include design reviews, an assessment of potential degradation mechanisms, industry --

experience for applicability, and inspections, as necessary, to ensure degradation of these

components does not threaten tube structural integrity and leakage integrity of the ability of the

plant to achieve and maintain' safe shutdown." Inspection requirements are based upon the

results of an assessment'which considers SG design, potential degradation mechanisms, and

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related FNP and industry operating experience.2 Inspection results are documented and, when

applicable, trends are used to alter the 'inspection requirements forisubsequent inspections.

The staff notes that the applicant performs monitoring activities, which are based on an

assessment that considers replacement SG ddsign' potential degradation mechanisms, and

FNP afid industry operating experience. In addition',;the staff notes that the applicant performs

trending, when'applicable, to alter inspection requirements for subsequent inspections.'

Therefore, the staff concludes that the applicant's Steam Generator Program incorporates

monitoring and trending activities will manag'e the degradation of secondary-side internals.-

With regard to acceptance criteria in its program, the applicant stated that the acceptance

criteria for inspections of secondary-side components are based on the inspection method and

engineering evaluation. Visual inspections typically use qualitative criteria for identifying

degradation sufficient to warrant further evaluation. Further evaluation may involve additional

inspection and engineering evaluation to quantify the amount of degradation (e.g., ultrasonic

testing to determine actual wall thickness and engineering evaluation to compare the results to

the design requirements)."Corrective actions can include followup inspections to assess the

rate of degradation or repair/replacement of the degraded component, or other actions as

deemed appropriate. When test or inspection results do not satisfy established acceptance

criteria, the applicant initiates corrective actions using a condition report. The staff concludes

that the applicant uses qualitative inspectio's, such as visual, to ascertain whether quantitative

inspections or engineering evaluations are warrarited to identify and compare the degradation'

to established acceptance criteria. Therefore, the staff concludes that the applicant's Steam

Generator Program incorporates the acceptance criteria and that the structure and component

intended functions of the secondary-side internals are and will be maintained. -

Section 3.0.4 of this SER addresses the Corrective Actions, Confirmation Process, and

Administrative Controls program'attributes in theirentirety.

With regard to operating experience, the applicant stated that its replacement SGs are

Westinghouse Model 54F with significant design and material improvements, as compared to

the original Westinghouse Model 5i SGs. ' To'date,'the applicant has not identified any ;

degradation of the Model 54F replacement SG secondary-side components. In addition', SNC

is not aware of any degradation of similar model replacement SGs within the industry. A review

of generic comimunications issued since NUREG-1 801 did not identify any applicable

degradation issues. The applicant's Steam Generator Program is a mature program with

significant operating experience, and was successfully used tomanage SG degradation of

secorndary-side internals in the original Model 51 SGs. The'staff finds that the applicant's

operating experience with the recently replaced 'SGs shows no applicable degradation issues,

and that sufficient evidence exists'to'support the conclusion that the structure and component'

intended functio6ns of the secondary-'side iiterrnali'will be maintained during the' period of

extended operation. -*

On the basis of the informatioh submitted, the'staff finds that the applicant's Steam Generator -

Program is adequate to manage the effects of aging of the SG secondary-side internals in the

FNP steam generators. . . -

FSAR Supplement

The applicant's FSAR Supplement states that the Steam Generator Program,'which is based

3-19
on NEI 97-06 and used to perform tube surveillance, is consistent with the TS. The applicant

also stated that the Steam Generator Program is consistent with the 10 attributes of the GALL

AMP XI.M1 9. However, the FSAR does not describe the management of the aging effects of

the SG secondary-side internals. By letter dated March 22, 2004, in RAI 3.1.2.4-6, the staff

requested that the applicant state in the FSAR that the aging effects of the SG secondary-side

internals will be managed in a manner consistent with the attributes described in RAI 3.1.2.4-5.

In its response to RAI 3.1.2.4-6 dated April 22, 2004 (SNC Letter No. NL-04-0678), the

applicant responded by stating that it will revise Section A.2.7 of the FSAR Supplement as

follows (changes indicated by bold italics):

A.2.7 STEAM GENERATOR PROGRAM

The Steam Generator Program used to perform replacement steam generator tube surveillance in

accordance with the Technical Specifications will be continued during the period of extended

operation. The program Includes monitoring of steam generator secondary side internal

components whose failure could prevent the steam generator from fulfilling its Intended

safety-related function. This program will be based upon NEI 97-06, 'Steam Generator Program

Guidelines" or its successors.

The staff finds the revised FSAR Supplement acceptable because it includes a description' of

how the Steam Generator Program will manage the secondary-side internals, consistent with

the applicant's response and the GALL Report.

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the applicant

has demonstrated that the Steam Generator Program will effectively manage aging in the SG

components for which this program is credited and will ensure that the SGs will perform their

intended function in accordance with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff reviewed the associated FSAR Supplement for this

AMP and concludes that the FSAR Supplement provides an adequate summary description of

the program, as required by 10 CFR 54.21 (d).

3.0.3.1.3 Summary of Conclusion for AMPs That Are Consistent with the GALL Report

On the basis of its review and audit of the applicant's AMPs, the staff concludes that for the

AMPs listed above, 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 reviewed the

associated FSAR Supplement for these AMPs and concludes that the FSAR Supplement

provides an adequate summary description of the programs, as required by 10 CFR 54.21 (d).

3.0.3.2 AMPs That Are Consistent with the GALL Report, but with Exceptions and/or

Enhancements

In Appendix B to the LRA, the applicant indicated that the following AMPs were consistent with

the GALL Report with exceptions and/or enhancements:

* Water Chemistry Control Program (B.3.2)

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* Reactor Vessel Surveillance Program (B.3.4)

* Fuel Oil Chemistry Cofitrol Program (B.4.2)

* Structural Monitoring Program (B.4.3)

* Service Water Program (B.4.4)

* - - Fire Protection Program (B.4.5)

* Reactor Vessel Internals Program (B.5.1)

* Non-EQ Electrical Cables Used in Instrumentation Circuits Program (B.5.6.1)

* ;Flow-Accelerated Corrosion Program (B.4.1)

* Buried Piping and Tank Inspection Program (B.5.4)

For AMPs that the applicant claimed to be consistent with the GALL Report .with exceptions

and/or enhancements, the staff performed an audit to determine that those attributes or

features of the program for which the applicant claimed consistency with the GALL Report were

indeed consistent. Furthermore, the staff reviewed the exceptions and/or enhancement and the

applicant's justification to determine whether each AMP, with its exception and/or enhancement,

remains adequate to manage the aging effects for which it is credited. .The FNP Audit and,

Review Report documents details of the staff's evaluation of the FNP audit and review. The

staff also reviewed the applicant's exceptions and/or enhancements to the GALL Report to

determine whether they are acceptable. The following sections of this SER document the

results of the staff's audit and review.

'3.0.3.2.1 Water Chemistry Control ProgramI - -

Summary of Technical Information in the Agplication

Section B.3.2, "Water Chemistry Control Program," of Appendix B to the LRA describes the

applicant's Water Chemistry Control Program; -The applicant stated that the Water Chemistry

Control Program is an existing program that is consistent with GALL AMP XI.M2, 'Water

Chemistry," for primary and secondary water chemistry control, and is consistent with GALL

AMP XI.M21, "Closed-Cycle Cooling Water System," with an exception for closed cooling water

chemistry control.

The applicant stated that the Water Chemistry-Control Program will manage loss of material

and cracking within system components and structures, thereby ensuring continued structural

integrity, reliability, and availability. The program includes monitoring of detrimental species

and addition of chemical additives. The program utilizes the EPRI water chemistry guidelines in

establishing chemistry control procedures for.FNP. These documents are updated as

necessary to reflect improved guidance and industry experience.

Staff Evaluation - - ,: . - '

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL, Report. -The FNP. Audit and Review Report documents details of the staff's evaluation of

the FNP audit and review. Furthermore, the staff reviewed the exception and its justification to

determine whether the AMP, with the exception, remains adequate to manage the aging effects

for which it is credited.

In Section B.3.2 of Appendix B to the LRA, .the applicant stated that the Water Chemistry

Control Program for the closed-cycle cooling water (CCCW) systems and emergency-diesel

-3-21
II

generator (EDG) jacket cooling water is consistent with GALL Report AMP XLI.M21, with one

exception. With respect to the Water Chemistry Control Program for the CCCW systems, the

applicant takes exception to GALL performance testing for pumps' and heat exchangers,

choosing to utilize the EPRI monitoring guidelines instead. The applicant also credited a

focused, one-time inspection (using its One-Time Inspection Program) to validate the Water

Chemistry Control Program in low-flow and stagnant areas.

The staff reviewed the component cooling water (CCW) pump surveillance test results, the heat

exchangers condition report history since 1989, and the mechanical operating experience

report for the CCCW system. The staff concluded that the applicant's proposed exception is

acceptable on the basis that (1) the CCW pumps and heat exchangers have not experienced

any significant age-related failure, and (2) aging effects in the CCW can be monitored and

controlled by water chemistry control and corrosion inspection for components in systems

treated with corrosion-inhibiting material.

The staff reviewed'the One-Time Inspection Program. The staff concludes that using a onetime inspection (via the One-Time Inspection Program) to validate the Water Chemistry Control

Program in low-flow and stagnant areas is acceptable.

On the basis of its review of this AMP, the associated program master document, the relevant

station administrative procedure, and a sample of implementing procedures, the staff

determined that the Water Chemistry Control Program is consistent with the GALL Report, and

that the exception in the Water Chemistry Control Program is acceptable.

Operating Experience

The applicant stated that the Water Chemistry Control Program incorporates the best practices

of industry organizations, vendors, and utilities. The staff noted that most of the plant-specific

condition reports reviewed by the'applicant dealt with relatively minor instances of chemistry

parameters outside'of specified limits, 'and that prompt corrective-actions were taken to restore

water chemistry parameters within acceptable limits. In addition, the staff noted that the

applicant has incorporated the results of self-assessments into its Water Chemistry Control

Program, resulting in improvements in the program's chemical treatment methods, visual

inspection planning, and trending capabilities.

The staff finds that the applicant has aggressively pursued improvements in aging management

of in-scope components through improved chemical control methods, sampling and

measurement techniques, and installation of new equipment designed to mitigate aging effects.

The applicant has based its improvements on EPRI TR-1 05714, "PWR Primary Water

Chemistry Guidelines," dated January 1999. One improvement the applicant implemented was

to use materials more resistant to PWSCC in the replacement SGs. The applicant made

program changes to optimize chemistry control during startup/shutdown and to minimize entry

of contaminants into the primary water from makeup water sources, including the spent fuel

pool. The addition of zinc to reactor coolant, based on a recommendation in EPRI-TR-105714,

tends to reduce the potential for PWSCC and out-of-core shutdown dose rates.

Based on its review of the above operating experience, the staff concludes that the Water

Chemistry Control Program adequately manages the aging effects that have been observed at

the applicant's plant.

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FSAR Supllement

In Appendix A.2.2 to the LRA, the applicant provided the FSAR Supplement for the Water

Chemistry Control Program. The staff reviewed this section and determined that the ' information in the FSAR Supplement provides an adequate summary of the program activities.

The staff finds this section of the FSAR Supplement sufficient.

Conclusion - . . , . .

On the basis of its audit and review of the applicant's program, the staff finds that those

attriliutes of the program for which the applicanit c'aied conisistehcy with the GALL Report are

indeed consistent with GALL.' In addition, tie'staff reviewed the'exceptionrs t6 th6 GALL'Report

program and finds that the applicant has deinoiihtrated that the effects of aging will' ' adequately rmnanged so that the intende6d fuhnctions will be maintairid consist erit with the* CLB

for the period of extended operation, as required by '10 CFR 54.21(a)(3). The staff also' ' reviewed the FSAR Supplement for this 'AMP'and finds that it provides an adequate sumrnary'

description of the program, as required by 1 6FR -54.21 (d). - -

3.0.3.2.2 Reactor Vessel Surveillanc'Program' ' .'

Appendix H to 10 CFR Part 50 specifies the NRC requirements for reactor vessel materials

surveillance programs, which provid .Nhe re ratuor bsents for rplicait's Reactor m Vessel r

Surveillance Program for e th 1 gand 2.': ' f t ' p''c'n'' R Vessel FNP Unt 1 an -2.* i' - - -. - . -.

Summary of Technical Information in the ArDlication ' -

The applicant described the Reactor Vessel Surveillaice' Program in-Section B.3.4 of the LRA.

In this section of the LRA, the applicant stated 'iiat the Reactor Vessel Surveillance Program'is

a condition monitoring program which predicts changes in reactor vessel beltline material

fracture toughness. The program also evaluafts neutron embrittlement through surveillance

capsule testing and evaluation, fluence calculations and benchmarking, and monitoring of

effective full-power years (EFPYs). The applicant stated that the AMP applies the calculational

methodology of Regulatory Guide (RG) 1.190, "Calculational and Dosimetry Methods for

Determining Pressure Vessel Neutron Fluence," dated March 2001, for fluence calculations and

determinations. 'This RG provides the NRC guidelines for performing "best estimate" fluence

calculations.

Staff Evaluation . -

The staff's evaluation of the Reactor VesSurveillance Prograrn is based on its review of the

program descriptionin LRA Section B.3.4, as supported by pertinent information-documrented in

the staff's FNP Audit and Review Report.' The staff's criteria for accpting' th Reactor Vessel '

Surveillance Program are based on both conformrance with GALL AMP XL.M31 arid compliance

with the applicable requirements of Appendix H to 10 CFR Part 50..

The applicant stated that its Reactor Vessel Surveillance Program is consistent with GALL AMP

XL.M31 with thie following exception- - . ' ' '

The singular exception to the eight (8) acceptable program items described in NUREG-1 801

3-23
I

relates to SNC's proposed surveillance capsule removal schedule. NUREG-1801 specifies that all

remaining surveillance capsules are to be removed at a 60-year fluence and alternate dosimetry

installed. For FNP Unit 1, SNC has removed one capsule at a fluence approximately equivalent to

60 years. For FNP Unit 2, SNC will remove one capsule at a fluence approximately equivalent to

60 years. For each unit, one capsule will remain in the reactor vessel until a fluence of

approximately 80-years. -

The program discussion in GALL AMP XI.M31 is not currently based on the staff's

recommendations of the 10 program attributes that should be included within the scope of an

RV materials surveillance program, but rather on general recommendations of how an RV

materials surveillance program is expected to comply with the requirements of Appendix H to

10 CFR Part 50. The program should be modified, as applicable, to address the increases in

neutron fluences projected for the period of extended operation. Be6ause the applicant

considered the Reactor Vessel Surveillance Program to be an existing plant-specific program

for FNP, Units 1 and 2, it included a description of theA 0 program elements in Section B.3.4 of

the LRA. The staff included its evaluation of the Corrective Actions, Administrative Controls,

and Confirmation Process program attributes for the FNP Reactor Vessel Surveillance Program

within the scope of its assessment of the Quality Assurance Program for. the application. The

following paragraphs discuss the staff's evaluation of the remaining program attributes for the

FNP Reactor Vessel Surveillance Program. The evaluation of the applicant's exception to

GALL AMP XI.M31 is discussed within the Monitoring and Trending program attribute.

[Scope of Program] Reactoryessel materials suirveillance programs, which are designed and

implemented in accordance with Appendix H to 10 CFR Part 50, use testing on RV surveillance

capsule test specimens as the basis for monitoring neutron irradiation-induced embrittlement in

base metals (plates or forgings) and welds that are used to fabricate low-alloy steel fabricated

RVs. The applicant stated that the scope of the Reactor Vessel Surveillance Program

encompasses all reactor vessel beltline materials, including the RV lower and intermediate shell

plates, longitudinal welds, and circumferential welds.

Appendix H to 10 CFR Part 50 provides the following purpose for RV surveillance programs:

The purpose of the materials surveillance program required by this'appendix is to monitor for

changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline

region of light water nuclear power reactors which result from exposure of these materials to.

neutron Irradiation and the thermal environment. Under the program, fracture toughness test data

are obtained from material specimens exposed in surveillance capsules, which are withdrawn

periodically from the reactor vessel.

The base metal (i.e., either plate or forging materials) and weld materials in surveillance

capsule test specimens are generally representative of the base metal and weld materials that

are located in the beltline region of the RV. Therefore, the RV components identified by the

applicant as being within the scope of the Reactor Vessel Surveillance Program for FNP, Units

1 and 2, are consistent with those that are within the scope of Appendix H to 10 CFR Part 50.

The staff therefore concludes that the scope of the applicant's AMP is acceptable.

[Preventive Actions] The applicant stated that the Reactor Vessel Surveillance Program for

FNP, Units 1 and 2, is a condition monitoring program. Therefore, no preventive or mitigative

actions are associated with this AMP. Reactor vessel materials surveillance programs use RV

surveillance capsule test specimens as the basis for monitoring neutron irradiation-induced

embrittlement in the RV beltline base metal (plates and forgings) and weld materials. The staff

3-24
concurs that the Reactor Vessel SurveillanrcbPr6gram for FNP, Units 1 and 2, is a condition

monitoring program for the beltline base nietal rand w6ld materials in the RV shells, and

therefore does not include preventive or mitigative strategies. The staff concludes that the

applicant's Preventive Actions program attribute is acceptable.

! .. ' i '' . t' .

[Parameters ins ected or Monitored] and [Detection of Aging Effects] -The applicant stated that

the objective' of the Reactor Vessel Surveillance'Prgram' is to- periodically monitor a'nd project

reductions in the fracture toughn'ess of RV beltline materials. 'This is consistent with Section I of

Appendix H tol 0 -CFR Part 50 and is acceptable. The6 applicant also stated that the reductions

in fracture toughness due to neutron embrittlement are manifested ai aireduction of the uppershelf energy (USE) and an increase ih the nil'ductility reference temperature (RTN-T).CChanges

in these properties will also-result in chang&es to theip'redicted pressurized thermal shock (PTS)

reference temperature (RTPTS) values and pressure-teriperature (P-T) limit values.' The -:

applicant stated that tihi Re'actor Vessel Surveillance Program for FNP, Units'1 and 2,'detect

and project reductions in RV beltline material fra'ture toughness, such that n6 loss of the RV.

intended functions occurs.' ' ' ' i -

The applicant's Parameters Inspected or Monitored and Detection of Aging Effects program

attributes for the FNP Reactor Vessel Surveillance Program address'the impact that the RV 7

surveillance data (including neutron fluence dosimetry data, Charpy-V 'notch impact data,

tensile test, and alloying cherristry data, as obtained thlroigh implementation of the AMPs) will

have on fracture toughness properties assessed in' the-time-limited aging analyses' (TLAAs) for

neutron irradiation 'embrittlement (refer to Chapter 4:2 of the' LRA and Section 4.2 of this SER).

These TLAAs include the'TLAAs'on' USE,'adjusted reference temperature' calculations (RTNDT

calculations), and P-T limit calculation asse6smerits (as required'uniderthe provisions of

Appendix G tol1 CFR Part'50),:as well s' the TLAA for calculating RTPTsvalues, which is

required for PTS assessments (refer to the requirements of 10 CFR 50.61).- The program:

attribute descriptions als6 appropriately identify how the applicant will use the changes in the

fracture'toughness properties and parameters, as'monitored through implementation of the

'program, to assure that the 'structural'integrity of the RV and other reactor coolant pressure

boundary (RCPB) componhents is maintained. 'Based on'this assessment, the staff concludes

that the Parameters inspected or Monitored'ard Detection of Aging Effects program attributes

are acceptable. - ' ' ,!' - - -,

[Monitoring and Trending] The applicant stated that the Reactor Vessel Surveillance Program

monitors and trends predicted changes in vessel 'beltliribe mat6rial fraicture toughness properties,

and that it performis a reevaluation whenever new surveillance capsule-data become'available

or when' changes in 'operating parambte&rsocbur that rmay affect erid-of-license predictions of -

fracture toughness. The aplicant also 'indicated that the EFPYs for the reactor units'are also

monitored.'I2 - ' ' , - - --

During implementation of RV 'materials'surveillanice programs, the mronitoring and trending of

'fr'acture toughness properties is accomplished by the periodic iremoval and testing of

surveillance capsules during the operating'periods for the reactors. Appendix H to 10 CFR Part

50 fdquires the implementation of surveillance capsule withdrawal schedules to conform'to the

surveillance capsule removal criteria of American Society for Testing and Materials (ASTM) --

Standard Practice El 85, 'Standard Practice for Conducting Surveillance Tests for Light-Water

Cooled Nuclear Power Reactor Vessels," dated '1982. -The staff considers the edition of ASTM

El 85 in effect at the time'the RV was purchased to be acceptable, or any subsequent edition

--3-25
I

through the 1982 edition (ASTM E185-82) of the standard. Appendix H to 10 CFR Part 50 also

requires the applicant to submit proposed withdrawal schedules for NRC staff review and

approval.

The applicant took one exception to the provisions in GALL AMP XL.M31 and indicated that the

GALL program recommended that all remaining surveillance, capsules be removed at.

a 60-year fluence and alternate dosimetry installed. The applicant stated that instead of

meeting this recommendation,- for FNP, Unit 1, SNC has removed one capsule at a fluence

approximately equivalent to the peak RV fluence at 60 years of operation. For FNP, Unit 2, the

applicant stated that SNC will remove one capsule at a fluence approximately equivalent to the

peak RV fluence at 60 years of operation. The applicant also stated that one additional capsule

will remain in each of the RVs until each capsule receives an accumulated fluence equivalent to

the peak RV fluence for the reactor unit at approximately 80 years of operation. On February

23, 2004, as supplemented by its letter of March 5, 2004, SNC requested staff review and

approval of the changes to the Reactor Vessel Surveillance Program withdrawal schedules for

FNP, Units 1 and 2, to support operation through 60 years of licensed operation (i.e., through

54 EFPYs). The applicant's letters of February 23, 2004, and March 5, 2004, address the

identity of the capsules referred to in the applicant's exception and the specific details of the

times of removal and neutron fluence values for these capsules.

In its safety evaluation of March 15, 2004, the staff determined that, to accommodate license.

extension, the schedules for the remrioval of Capsules V and Z from the FNP Unit 1 RV and

Capsules Y and V from the FNP Unit 2 RV conform to ASTM El 85-82, if the criteria in the

standard are applied to the period of extended operation (60 years of licensed operation, or 54

EFPYs, in this case). Provision 6 of GALL AMP XL.M31 recommends that at least one capsule

be removed at a time when the fluence for the capsule is expected to be approximatelyequivalent to the projected peak RV neutron fluence at 60 years of operation. The applicant's

withdrawal of Capsule V from FNP, Unit 1, was performed when the accumulated fluence for

the capsule was equivalent to the projected peak RV neutron fluence for FNP, Unit. 1, at 54

EFPYs. The applicant's withdrawal of Capsule Y.fromr FNP, Unit 2, is to be performed when the

accumulated fluence for the capsule is approximately equivalent to the projected peakRV

neutron fluence for FNP, Unit 2, at 54 EFPYs. The applicant's withdrawal of Capsule V from

the FNP Unit 1 RV, and the projected withdrawal of Capsule Y from the FNP Unit 2 RV,

conform to the criteria in provision 6 of GALL AMP XL.M31 and are acceptable.

FNP Unit 1 Capsule Z and FNP Unit 2 Capsule V are supplemental in-vessel capsules that are

available for removal and testing to demonstrate operation beyond 60 years of licensed

operation. For plants with high lead factors (i.e., lead factors of approximately 3.0 or greater),

GALL AMP XL.M31 recommends that any remaining (supplemental) capsules in the RV be

removed and placed into storage for reinsertion at a later time. This will prevent overexposure

of the surveillance capsules before their removal, should an additional period of extended

operation be requested; The applicant has taken an exception .to this provision. Instead, the

applicant has stated that the FNP Unit 1, Capsule Z and the FNP Unit 2 Capsule V will remain in

the RVs, and that the capsules will be removed at the time when the neutron fluences for the

capsules are expected to correspond to the projected peak RV neutron fluence at 80 years of

operation for each unit.

In its letter dated March 5, 2004, the applicant provided its proposed withdrawal times and

projected neutron fluence values for FNP Unit 1 Capsule Z and FNP Unit 2 Capsule V. The

3-26
staff evaluated whether the projected neutron'fluences and withdrawal times for FNP Unit 1

Capsule Z and FNP Unit 2 Capsule V will provide relevant'data for 80 years of operation. Since

the removals of these capsules will be implemented at a time thatbcorresponds to the peak RV

fluence at 80 years of operation, it will not be necessary to minimize the exposure to these

capsules through a removal and reinsertion process. Instead, the applicant's exception and

proposed times of removal for FNP 1 Capsule Z and FNP Unit 2 Capsule V will ensure that the

neutron fluence exposures to the capsules are controlled (i.e., limited) so the withdrawals will

provide meaningful data for 80 years of operation.,

In Enclosure 2 of its letter dated July 27, 2004 (SNC Letter No. NL-04-1267), the applicant

provided Commitment No. 18 on the Reactor Vessel Surveillance Program, to address its plans

for implementing alternative dosimetry once the sixth surveillance capsules are removed from

the Farley, Units 1 and 2 RVs (i.e., Capsule Z for Farley, Unit 1, and Capsule V for Farley, Unit

2):

Reactor Vessel Surveillance Program:

For each unit, FNP wili install alternative d6simetrI to monitor neutron fluence on the reactor vessel after

removal of the last surveillance capsule in that unit. After all surveillance capsules have been removed, the

exposure conditions of the reactor vessel will be monitored to ensure consistency with those used to project

the effects of embrittlement to the end of the license period. Any plant operating restrictions (on parameters

such as inlet temperature, neutron flux, etc.) will be determined. The program will include provisions that if

reactor vessel exposure conditions are altered such that the analysis'assumptions could be invalidated,

appropriate actions will be performed (e.g., re-evaluation, re-instituting an active surveillance program,

notifying the NRC, etc.) to assure the adequacy of the projections to the end of the license period.

The applicant committed to implement this commitment after removal of the last surveillance

-capsule in each of the FNP units. 'Since the applicant's commitment addresses the need forimplementing alternative dosimetry after the final capsules have been removed, the applicant's

program conforms to the recommended provisions in GALL AMP XL.M31 for alternative

dosimetry implementation. Therefore, the staff concludes, that the applicant's exception to

remove the sixth capsules when the fluence for the capsules corresponds to the 80-year

fluence for th6 RVs', and commitment to implement alternative dosimetry prior to the following

startups of the reactors, are acceptable. Based ori-this assessment, the staff concludes that

the [Monitoring and Trending] program attribute for the RVSP is acceptable. 8~~ : ; : j , ; , ;.f i . . :

[Acceptance Criteria] ;The applicant stated that the capsule removal and analysis is performed

in accordance with the requirements of Appendix H to 10 CFR Part 50. The staff's evaluation

of the Monitoring and Trending program attribute includes a discussion of the staff's

consideration of the criteria for the capsule withdrawal schedules. For capsule test specimen.

analyses, the rule requires licensees to apply the test procedures and reporting requirements of

ASTM E185'82, to the extent practical,'for the configuration'of the test specimens in then .

capsule: 'The rule also requires'that the surveillance capsule test results be reported to the

NRC within 1 year of capsule removal. The staff finds that the applicant's acceptance criteria

for capsule test specimen analyses are acceptable because they appropriately reference the

test analysis and reporting requirements of Appendix H to 10 CFR Part 50.

The applicant also referenced the acceptance criteria (screening criteria) of 10 CFR 50.61 for

calculating the RTPTs values required forIPTS assessments, as well as the acceptance criteria

of Appendix G to 10 CFR Part 50 for USE determinations and P-T limit calculations. The staff

3-27 x 
II

finds these acceptance criteria to be acceptable because the applicant appropriately referenced

the correct requirements in 10 CFR Part 50 for these assessments. These acceptance criteria

are related to the individual TLAAs on neutron irradiation embrittlement of the RV beltline

materials. The staff evaluates these TLAAs in Section 4.2 of this SER.

[Operating Experience] In Appendix B.3.4.13 to the LRA, the applicant stated that the FNP

unit's surveillance specimens have been withdrawn and tested in the past, and data from these

surveillance capsules and from other industry sources have been used to verify and predict the

performance of the FNP RV beltline materials with respect to neutron embrittlement.

The following Westinghouse topical reports document the design for the Reactor Vessel

Surveillance Program for FNP, Units 1 and 2:

WCAP-8810-for FNP, Unit 1

* WCAP-8956-for FNP, Unit 2

The applicant has reported the test results for the following FNP Unit 1 surveillance capsules to

the NRC, in accordance with the reporting requirements of Appendix H to 10 CFR Part 50:

* Capsule Y-data reported in WCAP-9717 and reassessed in WCAP-1 6221 -NP

* Capsule U-data reported in WCAP-1 0474 and reassessed in WCAP-1 6221-NP

* Capsule X-data reported in WCAP-11563 and reassessed in WCAP-1 6221 -NP

* Capsule W-data reported in WCAP-14196 and reassessed in WCAP-1 6221-NP

* Capsule V-data reported in WCAP-1 6221-NP

The applicant has reported the test results for the following FNP Unit 2 surveillance capsules to

the NRC, in accordance with the reporting requirements of Appendix H to 10 CFR Part 50:

Capsule U--data reported in WCAP-1 0425 and reassessed in WCAP-1 5171

* Capsule W-data reported in WCAP-1 1438 and reassessed in WCAP-15171

* Capsule X-data reported in WCAP-1 2471 and reassessed in WCAP-1 5171

* Capsule Z-data reported in WCAP-1 5171

In its Operating Experience program attribute, the applicant stated that it may use other industry

surveillance data relevant to the neutron irradiation embrittlement assessments (i.e., PTS, USE,

and P-T limits) that are required for FNP, Units 1 and 2. Because SNC indicated that it might.

apply surveillance data from sources other than the FNP Reactor Vessel Surveillance Program

to the neutron irradiation embrittlement assessments for FNP, Units 1 and 2, the staff -

requested that SNC provide additional information on which supplemental surveillance data it

would apply to the neutron irradiation embrittlement assessments for: FNP, Units 1 and 2. The

staff also requested that SNC justify why it considers the supplemental surveillance data to be

valid for incorporation into these assessments. In the RAI, the staff requested that SNC clarify

how it applied RV surveillance data from other plants to the assessments of its TLAAs,

including those for adjusted reference temperature, USE, PTS ,and P-T limit calculations. The

staff issued these requests in RAI B.3.4-1.

The applicant provided the following response to RAI B.3.4-1 in its letter dated May 10, 2004

(SNC Letter No. NL-04-0831):

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In response to Generic Letter 92-01, Revision 1, Supplement 1, SNC applied all relevant industry

data to determine 'best estimate copper and nickel values for FNP weld material. FNP's result

was that using the 'best estimate" copper and nickel content for FNP weld material did not cause

the weld material to become limiting so FNP's neutron irradiation embrittlement assessments were

not affected. The NRC has already accepted FNP's response to Generic Letter 92-01 and no

additional supplemental or external data Is expected to be applied to the Farley Reactor Vessel

.Surveillance Program. ,.,j .- .- -

The applicant's response to RAI B.3.4-1 indicatesl that the industry data the applicant is

referring to are the relevant industry "best-etimat copper and nickel alloying values compiled

by Combustion Engineering (CE) for CE-fabricated RV weld materials. The CE RVs that are

within the scope of CE's generic alloying chemistry evaluations include the FNP RVs -The staff

issued its RAls on GL 92-01, Revision 1, Supplement 1, to ensure that licensees owning U.S.

light-water reactors would apply all relevant' copper and nickel 'alloy chemistry data for their RV

beltline welds to the RV integrity assessments forrth6eir vessels. !For license renewal purposes,

these structural integrity assessments are 6th6e TLAAs on neutron irradiation embrittlement; for

FNP, these include the TLAAs on USE assessments, assssents for PTS, adjusted ref erence

temperature calculations (RTNDT value calculations) for the 1/4T and 3/4T locations of the RVs,

and the P-T limits for the RVs. ' '' .. f 'ha . .. o frm di 6 )r ;, ::.,.. . .; - -. . -. - ; -

The staff has confirmed in its review of the TLAAs on neutron irradiation embrittlernent that the

applicant has applied all reldvant copper'and nickel alloy chemistry data' to the assessmnents.

Section 4.2 of the LRA includes these assessments and Section 4.2 of this'SER presents thestaff's evaluation of them: Because the applicant has clarified the type of external surveillance

data it applied, and because the staff has validated that the applicant has applied all relevant

copper and nickel alloy chemistry data to' its TLAs'on neutron irradiation embrittlement, the

staff concludes that the applicant's response'to RAI B.3.4-1 is acceptable. RAI B.3.4-1 is,

resolved. The staff also concludes that the Operating Experience program attribute is

acceptable because the applicant has considered all of the surveillance data that are applicable

to the Reactor Vessel Surveillance Program and the TLAAs on neutron irradiation.

embrittlement. '

In its conclusion for the Reactor Vessel Surveillance Program, the applicant stated that the

program will be 'maintained in compliance with the requirements of 10 CFR Part 50, Appendix

H, with NRC-approved exceptions.". This conclusion, as stated in the version of Section B.3.4

submitted with the application, created some ambiguity as to the types of exceptions from

Appendix H to 10 CFR Part 50 the applicant referred. As required by 10 CFR 50.60(a),

licensees of operating U.S. light-water reactdrs' must implement the fracturie toughness

requirements of Appendix G to 10 CFR Part 50,'and the reactor vessel surveillance program

requirements of Appendix H to 10 CFR Part 50. Title 10, Section 50.60(b), of the Code of

Federal Regulations permits licensees to use proposed alternatives to the requirements in

these appendices,- if an 'exemption is requested and granited by the Comris ion' under the

exemption provisions of 10 CFR 50.12. The staff indicated to the applicant that it did not have'

an issue with the conclusion for the Reactor Vessel Surveillance Program, if the exceptions to

which the applicant referred are exemptions it requested under the provisions of 10 CFR

50.60(b) and granted by the staff under 10 CFR 50.12. However -if the exceptions pertain to"

any deviations from the pertinent requirements of Appendix H to 10 CFR Part 50, as identified

as exceptions to program attributes of GALL AMP XL.M31, the staff informed the applicant that

10 CFR 50.60(b) requires that the exceptions be submitted as exemptions from the'

requirements of Appendix H to 10 CFR Part 50. The staff must approve any exemptions the

3-29
II

applicant submits, in accordance with the five exemption acceptance criteria specified in the

provisions of 10 CFR 50.12.

The staff therefore requested that the applicant modify the conclusion section for the Reactor

Vessel Surveillance Program (LRA AMP B.3.4) to state that, "The RVSP will be implemented

and maintained in accordance with the requirements of 10 CFR Part 50, Appendix H, unless

alternatives to the requirements of the rule are requested under 10 CFR 50.60(b) and granted

under 10 CFR 50.12." Otherwise, the staff requested that the clause 'with NRC-approved

exceptions" be deleted from the Conclusion section of the AMP. The staff identified this issue

as RAI B.3.4-2.

The applicant responded to RAI B.3.4-2 in a letter dated May 10,'2004 (SNC Letter No. NL-04-

0831). In the response, the applicant clarified that the exceptions in the Conclusion section for

the Reactor Vessel Surveillance Program refer to any exemptions to Appendix H to 10 CFR

Part 50 requested under the'requirements of 10 CFR 50.60 and granted in compliance with one

of the exemption acceptance criteria of 10 CFR 50.12. Based on this response, the staff

concludes that the applicant's response to RAI B.3.4-2 is acceptable because the applicant has

clarified that the exceptions it referred to in the conclusions are exemptions requested and

granted under the NRC's exemption approval processes. The staff also considers that the

applicant's conclusion for the Reactor Vessel Surveillance Program is acceptable because it

validates that the applicant will continue to implement the program iri accordance with the

requirements of Appendix H to 10 CFR Part 50, with the exception that the additional

requirements of the license condition stated in Section 3.0.3.2.2.3 6f this SER will also apply to

the program's scope and implementation. Section 3.0.3.2.2.3 of this SER discusses the basis

for issuing the additional license condition on the Reactor Vessel Surveillance Program.

FSAR Supplement

Section A.2.4 of Appendix A to the FNP LRA provides the applicant's FSAR Supplement

summary description for the Reactor Vessel Surveillance Program. In this section of the LRA,

the applicant provided the following summary description for the Reactor Vessel Surveillance

Program:

The Reactor Vessel Surveillance Program will be used to predict changes' in reactor vessel beitline

material fracture toughnessduring the period of extended operation. The program will be used to

evaluate neutron embrittlement through surveillance capsule testing and evaluation, fluence

calculations and benchmarking, and monitoring of effective full power years (EFPYs). For fluence

calculations, FNP uses Regulatory Guide 1.190 which provides for a "best estimate" fluence

calculation.

This FSAR summary description' provides an acceptable general description of the FNP

Reactor Vessel Surveillance Program. However, Appendix H to 10 CFR Part 50 requires

licensees to submit any proposed changes to their RV surveillance programs' withdrawal

schedules to the NRC for review and approval. To ensure that this reporting requirement will

carry forward after the FNP operating licenses have been renewed, the staff is imposing the

following condition in the renewed licenses for FNP, Units 1 and 2:

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

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

must be maintained for future insertion. Any changes'to storage requirements must be approved

.by the NRC.

Conclusion

On the basis of its review and audit of the applicant's program, the staff finds that the program

attributes for the Reactor Vessel Surveillance Program are acceptable and that the applicant

has demonstrated that the effects of aging will be-adequately managed so that'th6 intended

functions 'will be maintained consistent withth'e CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3)." The staff also reviewed the FSAR Supplement for this AMP

and finds that it provides an adequate summiary description of the program, as required by 10

CFR 54.21 (d).

3.0.3.2.3 Fuel Oil Chemistry Control Program

Summary of Technical Information in the ApDlication

Section 4.2 of Appendix B to the LRA, uFuel Oil Chemistry Control Program," describes the'

applicant's Fuel Oil Chemistry Control Program. -The applicant stated that the program is,

consistent with GALL AMP XI.M30, "Fuel Oil Chemistry," with an exception and "an

enhancement. The applicant credited this AMP with monitoring aging management of the loss

of material from the emergency diesel fuel oil system components. '

The applicant also stated that the FNP Fuel Oil Chemistry Control Program is governed by'

FNP's TS.:'These include'surveillance and rmaintenance procedures to mitigate corrosion, as

well as measures to verify the effectiveness of this AMP and confirrii the absence of an aging

effect. :

Staff Evaluation

During its audit and review, the staff confirmed thieajlplicant's claim' of consistency with the

GALL Report. The FNP Audit and Review Report documents details of the staff's evaluation of

the FNP audit and review; 'Furthermor6,-the staff reviewed the program's exception and

enhancement and its justification to determine whether the AMP,' with 'the' 6xption and

enhancement, remains adequate to managae'the6'aing effects for 'which it is credited.-

In accordance with its TS, the applicant uses ASTM D270-65 to perform fuel oil sampling and

sample analysis. GALL AMP XI.M30 prescribes ASTM D4057. The applicant compared the

standards cited in the plant TS against the standards cited in the GALL Report. The'Fuel Oil

Chemistry Control Program performs water, sediment, and viscosity analyses; however, the

program does not credit 'particulat6'analysis of fuel 6i1 for aging mana'erit. Particulate

analysis is performed on diesel fuel to address diesel performan'ce concers -(i.e.,-filter

clogging) and does not have a significant impact on pressure bounudaryintegrity. Th6 applicant

stated that because the parameters important to corrosion are monitored by the program, no

significant difference exists in the'ability of th'ep'rogram to rn- anagb adinrg effects.: The applicant

stated that operating experience confirmrs that th6 Fui1 Oil Chemistry Control Program has

been effective in managing aging. -7:1 -' ' ' * ""'

'3-31
I ai

The staff reviewed the exception concerning the ASTM standards, which the applicant uses in

accordance with TS Section 5.5.13. The applicant tests for water and sediments, kinematic

viscosity, insolubles, bacteria, and fungi. The applicant does not test for particulates, as

required by the GALL Report. The staff determined that this exception is acceptable because

sediments are a good indicator of particulates, and the applicant uses standards and criteria

that are consistent with the TS requirements contained in the CLB.

The applicant stated that it will evaluate the scope of the program, as an enhancement, and the

need to improve procedural guidance for maintaining and monitoring the diesel-driven fire pump

fuel oil system. If changes are necessary, the applicant will implement the changes before the

period of extended operation. The staff determined that this enhancement is acceptable

because any such changes will provide additional assurance that the effects of aging will be

adequately managed. The applicant addressed this enhancement in Appendix A, FSAR

Supplement, under A.2.9, Fuel Oil Chemistry Control Program, of the LRA. In addition, by letter

dated July 27, 2004, the applicant included this enhancement as a commitment in its FNPLicense Renewal Future Action Commitments.

In its letter dated May 28, 2004 (SNC Letter No. NL-04-0924), the applicant provided its errata

information to the LRA. In errata item no. 4, the applicant stated that for component types 'Fuel

Oil Storage Tanks" and "EDG Day Tanks" in Table 3.3.2-14, the One-Time Inspection Program (in addition to the Fuel Oil Chemistry Program) should be listed in the Aging Management

Programs column for the fuel oil environment only. In Section B.5.5, One-Time Inspection

Program, under the Detection of Aging Effects element, the applicant stated that it will perform

one time inspections on selected components using proven nondestructive (NDE) methods

including visual, volumetric, surface techniques, and hardness testing, as applicable to the

selected components. The applicant credited the Fuel Oil Chemistry Control Program (AMP

B.4.2) and the One-Time Inspection Program (AMP B.5.5) with managing the'aging effect of

loss of material for diesel fuel oil tanks in the diesel fuel oil system, which is consistent with the

GALL Report, with one exception, which was discussed above. Section 3.3.2.2.7 of this SER

contains staff's further evaluation of loss of material in the diesel fuel oil system to verify the

effectiveness of the Fuel Oil Chemistry Control Program.

On the basis of its audit and review of this AMP, the associated program master document, the

relevant station administrative procedure, a sample of implementing procedures, and its letters

dated May 28, 2004 and July 27, 2004, the staff determined that the Fuel Oil Chemistry Control

Program is consistent with the GALL Report, and that the program's exception and

enhancement are acceptable.

Operating Experience,

The staff reviewed the operating experience associated with the Fuel Oil Chemistry Control

Program. Condition reports were found which documented abnormalities, such as leakage at a

pipe nipple and failed moisture and sediment testing.

Based upon a condition report and work order search, the staff determined these instances

were isolated, rather than' systemic, and did not indicate programmatic' failure. The staff also

confirmed that the applicant cleaned and performed visual inspections of several EDG fuel oil

storage tanks. The applicant has found the overall condition of the tanks to be satisfactory and

has not noted any significant degradation.

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Based on its review of the operating experience, the staff concludes that the Fuel Oil Chemistry

Control Program adequately rnanages the aging effect that has been observed at the

applicant's plant.

FSAR Supplement

In Appendix A.2.9 to the LRA, the applicant provided the FSAR Supplement for the Fuel Oil

Chemistry Control Program. The staff reviewed this section and determined that the

information in the FSAR Supplement provides an adequate summary of the program activities.

The staff finds this section of the FSAR Supplement sufficient.

Conclusion - -

On the basis of its audit and review 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 GALL. In addition, the staff reviewed the applicant's exception and the

enhancement to the GALL Report program and finds that the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the FSAR Supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.4 Structural Monitoring Program

Summary of Technical Information in the-Application

Section B.4.3, "Structural Monitoring Program," of the LRA describes the applicant's Structural

Monitoring Program. The applicant stated that the Structural Monitoring Program is consistent

with GALL AMPs Xl.S5, "Masonry Wall Program," and Xl.S6, "'Structures Monitoring Program,"

with enhancements. Further, the applicant stated that it uses the Structural Monitoring Program

to monitor the condition of structures and structural components within the scope of the

Maintenance Rule, and, as a result, indicated that there is no loss of structure or the structural

component intended function. The Structural Monitoring Program also includes the masonry

walls identified in NRC Inspection and Enforcement (IE) Bulletin 80-11, and NRC Information

Notice (IN) 87-67.

Staff Evaluation ' -

During its-audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The FNP Audit and Review Report documents details of the staff's evaluation of

the FNP audit and review. -Furthermore, the staff reviewed the enhancement and itsI

justification to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited.;

.. 1 -t I, - , I . -' . -

The FNP Structural Monitoring Program will be enhanced to monitor structures and structural

components that are within the scope of license renewal, but are not currently monitored by the

program. An enhancement will also be made to the Structural Monitoring Program to clarify the

hangers and supports to be inspected in Category I buildings. The staff reviewed these

enhancements and found them to be acceptable on the basis that these components require

.3-33
aging management, and therefore, need to be included in this program. The applicant has

included its commitment to enhance the program in Appendix A.2.1 0 to the LRA.

On the basis of its review of this AMP, the associated program master document, the relevant

station administrative procedure, and a sample of implementing procedures, the staff

determined that the Structural Monitoring Program is consistent with the GALL Report, and that

the program enhancement is acceptable.

Operating Experience

The staff reviewed the operating experience associated with the Structural Monitoring Program.

The applicant stated that a formal operating experience program is in place at FNP, and that

improvements have been made to the Structural Monitoring Program. Plant-specific operating

experience is derived from condition report searches, personnel interviews, and Structural

Monitoring Program inspection report reviews.

The applicant indicated that baseline inspections conducted during the period of June 1996

through August 1997 established a reference in time for comparison to future inspections.

Periodic inspections commenced in April 2000. The inspections conducted during the first 5-

year period included all accessible areas in the scope of the Structural Monitoring Program.

The staff's assessment of the program's operating experience review concluded that

administrative controls are in effect and are effective in identifying age-related degradation and

initiating corrective action.

Based on its review of the above operating experience, the staff concludes that the Structural

Monitoring Program adequately manages the aging effects that have been observed at FNP.

FSAR SuDplement

In Appendix A.2.10 to the LRA, the applicant provided the FSAR Supplement for the Structural

Monitoring Program. The staff reviewed this section and determined that the information in the

FSAR Supplement provides an adequate summary of the program activities. The staff finds

this section of the FSAR Supplement sufficient.

Conclusion

On the basis of its audit and review 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 GALL. In addition, the staff reviewed the enhancements to the GALL

Report program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation; as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the FSAR Supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.5 Service Water Program

Summarv of Technical Information in the Application

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Section B.4.4. "Service Water Program," of the LRA describes the Service Water Program.

The applicant stated that the Service Water Program is consistent With GALL AMP XL.M20,

"Open Cycle C6oling Water System (OCCW)," with an enhancement.

The applicant stated that the Service Water Program activities implement the recommendations

of GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment." Program

activities include mitigation, as well as performance and condition monitoring techniques that

manage fouling and loss of material in the service water (SW) system and associated

components.

The applicant stated that the Service Water Program prevents or mitigates fouling and loss of -

material in the service water system and components, in part, by intermittent injection of the

appropriate water treatment chemicals. Other preventive aspects of the Service Water -,

Program include periodic flushing of low-flow and stagnant lines to mitigate or prevent fouling,-,

and heat exchanger cleaning at regular intervals. Volumetric examination may be used to

detect pipe wall thinning. The applicant visually inspects some components for fouling or loss

of material.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The FNP Audit and Review Report document details of the staff's evaluation of

the FNP audit and review. Furthermore,- the staff reviewed the enhancement and its

justification to determine whether the AMP, with the enhancement, remains adequate to

manage the aging effects for which it is credited. - : . : : .. . - ; - -,, l - ,

The applicant stated, in Appendix B to the LRA,- that the scope of the Service Water Program

will be enhanced to include inspection of piping from the main service water header to the air

compressor credited for Appendix R safe shutdown and the inspection of the service water

pump columns. The staff reviewed this enhancement and found it to be acceptable on the

basis that these components require aging management per 10 CFR 54.4, and therefore, this -

enhancement is needed. Appendix A.2.1 1 to the LRA addresses this commitment. n

On the basis of its review of this AMP, the associated program master document, the relevant

station administrative procedure, and a sample ofimplementing procedures, the staff

determined that the Service Water Program is consistent with the GALL Report, and that the

enhancement in the Service Water Program is acceptable. - -

Operating Experience - . . .

The applicant stated in the LRA that program inspections and plant observations have revealed

some instances of local loss of material, much of it in stagnant sections of piping.' There has

also been evidence of loss of material in the containment cooler, CCW, and diesel generator

heat exchangers. The applicant has taken corrective actions. Fouling was found to have

occurred, including biofouling (e.g., live clams);- Corrective actions included procedure revisions

and an engineering evaluation to determine flushing needs. The applicant continues to find

evidence of microbiologically influenced corrosion (MIC) without severe problems or loss of

intended function.

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I

The staff reviewed the applicant's operating experience report, which includes specific

operating experience for the Service Water Program. The operating experience includes

issues with biofouling and loss of material which the applicant documented and corrected. The

staff noted that the applicant's implementation of GL 89-13 at FNP more than a decade ago has

proven effective in managing fouling and loss of material in piping and components of the

service water system.

Based on its review of the above operating experience, the staff concludes that the Service

Water Program adequately manages the observed aging effects at FNP, Units 1 and 2.

FSAR Supplement

In Appendix A.2.1 1 to the LRA, the applicant provided the FSAR Supplement for the Service

Water Program. The staff reviewed this section and determined that the information in the

FSAR Supplement provides an adequate summary of the program activities. The staff finds

this section of the FSAR Supplement sufficient.

Conclusion

On the basis of its audit and review 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 GALL. In addition, the staff reviewed the enhancement to the GALL

Report program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the FSAR Supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.6 Fire Protection Program

Summary of Technical Information in the Aonlication

Section B.4.5, "Fire Protection Program," of the LRA describes the applicant's Fire Protection

Program. The applicant stated that the program is consistent with GALL AMPs XL.M26, "Fire

Protection,' and XI.M27, 'Fire Water System", with enhancements. The applicant stated that

the Fire Protection Program will provide inspections, performance testing and monitoring, and

aging management activities during the period of extended operation for water-and gas-based

fire protection systems, fire dampers, fire doors, fire penetration seals, cable wrap, and fire

pump diesels (including the external surfaces of exposed fuel oil piping). The applicant

indicated that this program will detect loss of material, fouling, cracking, and change in material

properties (CO2 tank insulation) in the applicable fire protection components.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The FNP Audit and Review Report documents details of the staff's evaluation of

the FNP audit and review. Furthermore, the staff reviewed the enhancements and its

justification to determine whether the AMP, with enhancements, remains adequate to manage

the aging effects for which it is credited.

3-36
The staff identified differences in' the frequency of tinspections used at FNP. Specifically, the

applicant tests C02 and Halori systems every 18 months, instead of biannually as

recommended by the GALL Report. 'Thepp i6cat's fire door inspection frequency is also

every-18 months, in'stead of biannually, as recr6iimended by the GALL Report. The applicant'

inspects yard hydrants annu'ally, instad of bihnnially'as recommended by the GALL Report.'.

The staff reviewed the applicant's basis document, plant operating experience, and fire

surveillance procedures. Be~casue thes6e aging' effects occur over a considerable period of time,

the staff concludes that the 1 8-inbhthin'spection interval will be sufficient to detect aging of

C02,- Halon, 'and fire doors. The staff also cochluded that the applicant's annual visual

inspection of the yard hydrants will be bufficient. -_-' 

The applicant made the following four enhancements to the GALL Report elements:'; -

"'(1) The fire protection sprinkler system piping will be subjected to wall thickness evaluations

(e.g., nonintrusive volumietric testingrai'd/or visual inspections'during plant maintenance)

before'the period of extended operation and'at specific intervals thereafter. .The'.,-

plant-specific inspection interval will be established from the initial inspection results and

revised as appropriate on'the basis of subsequent inspection results.

(2) A sample of sprinkler heads will be inspected by using the guidance of Section 5.3.1.1.1

of National Fire Protection Association (NFPA) 25, "Inspection, Testing and - Maintenance of Water-Based Fire'Protectioh Systems," at or before 50 years of service

'and every 10 years thereafter. if - --

(3) Diesel-driven'fire pump surveillarice'procedures will be upgraded to provide more

detailed instructions related to inspection of the fuel oil supply piping.

(4) The currenit practice of replacing C02 hoses at 5-year intervals will be formalized in fire

protection procedures. i' -

The staff determined that the enhancement to include the sprinkler piping and sprinkler heads

within the scope of this program is acceptable because they are exposed to the sameenvironment as the other in-scope components.' - . -

Interim Staff Guidance (ISG)-04 revised the criteria for the GALL AMP XL.M27 Parameters ' Monitored or Inspected program element to no longer recommend the use of GL 89-13 in

determining the system's ability, to maintain 'pressure-and internal system corrosion conditions.

RathebrlSG-04 recomm ernds' either periodic flow testing of the fire water system using the

guidelines of NFPA 25,'at the maxirhurn design flow, or periodic wall thickness evaluations to

ensure that the system maintains its intended function. Based on the applicant's'commitment

to inspect fire water system components, the staff determined enhancement (1) to be

acceptable and to satisfy ISG-04. - -,

ISG-04 revised criteria for the GALL AMP AX.M27-Detection of Aging Effects program element

to recommerid sprinkler head inspections before the'end of the 50-year.sprinkler head service

life and at 1 0-year intervals thereafter during the period of extended operation to ensure that

signs of degiradation are detected in a timely manner.,- Based on the revised GALL Report

criteria in ISG-04, and the applicant's commitment to rely upon applicable'codes and standards

' 3-37
._ a

to develop test procedures, the staff determined enhancements (2)-(4) to be acceptable.

The applicant addressed aforementioned enhancements (1) through (4) in Appendix A, FSAR

Supplement, under A.2.12, Fire Protection Program, of the LRA. In addition, by letter dated

July 27, 2004, the applicant- included these enhancements as a commitment in its FNP-License

Renewal Future Action Commitments.

On the basis of its review of this AMP, the associated program master document, the relevant

station administrative procedure, and a sample of implementing procedures, the staff

determined that the Fire Protection Program is consistent with the GALL Report, that ISG-04 is

satisfied, and that the enhancements in the program are acceptable.

Operatina Experience

The applicant stated in the LRA that since the inception of the Fire Protection Program, ongoing

internal and external assessments have been performed, including the NRC's triennial

inspections. These assessments effectively identified programmatic strengths and weaknesses

and prompted corrective actions. Inspections, performance testing, and performance

monitoring by the existing Fire Protection Program have been effective in managing age-related

degradation so that corrective actions are taken well before a loss of intended function could

occur.

Specific operating experience indicates that there have been occasions in which loss of material

occurred along the bottom of specific sections of normally dry fire protection piping. The

applicant indicated that it had attributed this to drainage problems associated with operational

or design/installation practice, and it has taken corrective actions to prevent recurrence.

With regard to the CO2 system, the applicant conducted a review which covered approximately

15 years of operation. The results indicated very few age-related instances requiring

maintenance. Most of the items involved replacement of bulbs, valve seals, rubber seats, and

pilot valve seat discs.

Based on its review of the above operating experience, the staff concludes that the Fire

Protection Program adequately manages the aging effects that have been observed at FNP.

FSAR Supplement

In Appendix A.2.12 to the LRA, the applicant provided the FSAR Supplement for the Fire

Protection Program. The staff reviewed this section and determined that the information in the

FSAR Supplement provides an adequate summary of the program activities. The staff finds

this section of the FSAR Supplement sufficient.

Conclusion

On the basis of its audit and review 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 GALL. In addition, the staff reviewed the enhancements to the GALL

Report program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

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for the period of extended operation, as required by10 CFR 54.21 (a)(3). The staff also

reviewed the FSAR Supplement for this AMP and finds that it provides an adequate summary

description -of the program, as required by 10 CFR 54.21(d).

3.0.3.2.7 Reactor Vessel Internals Program

Summarvof Technical Information in the Application

The applicant described the Reactor Vessel Internals Program in LRA Section B.5.1. The

applicant's discussion in LRA Section B.5.1 indicates that the Reactor Vessel Intemals Program

incorporates program attributes from both GALL AMPs XI.M1 6, UPWR Vessel Internals," and

Xl.M13; uThermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless

Steel (CASS)." - . - ; -l - -

In its letter dated April 29, 2004 (SNC LetterNo. NL-04-0715), the applicant revised its scope

and description of the'Reactor Vessel Internals Program to indicate that the AMP is based on

the following industry initiative and attributes: -'-. -

* SNC will continue to participate in the industry's Initiatives intended to clarify the nature and

extent of aging mechanisms potentially affecting reactor vessel internals.

* SNC will incorporate the results of these initiatives (to the extent that they are applicable to the - FNP reactor internals) into the scope, Inspection requirements (including inspection locations, methods, qualifications, and frequencies), acceptance criteria, and corrective actions for the

RV Internals Program;. "'

* SNCwill submit an inspection plan for the FNP RV Internals Program for NRC review and*-

approval at least 24 months prior to entering the periods of extended operation for the FNP

units. .

* The FNP RV Internals Program is consistent with the 10 attributes of the aging management

program described in NUREG 1801 -Section XL.M13 and Section XI.M16, except as

described above.

Staff Evaluation

[Scope of Program] The applicant stated that the Reactor Vessel Internals Program is a new,

integrated inspection program credited with the management of (1) crack initiation and growth

due to irradiation-assisted stress-corrosion cracking (IASCC), (2) loss of fracture toughness due

to irradiation embrittlement, thermal embrittlement, or void swelling, and (3) changes in material

properties as a result of void swelling. The applicant indicated that the program will supplement

the RV internals (core support structures) inspections required by the ASME Code, Section Xi,

Subsection IWB Inservice Inspection Program, Category B-N-3. .I

... .,;- --- ,4 *' 4-- - - * -

In Section 3.1.3.1.2 of this SER, the staff evaluates the mechanisms that could induce loss' of

material in nickel-chromium-iron (NiCrFe) and stainless steel RV internal components given -

exposure to borated water. In RAI 3.1.3.1.2-1, parts a and b, the staff requested infdrmation

about the different aging mechanisms that could induce loss of material in the NiCrF6 and

stainless steel RV internal components and justification as to why the applicant'cornsiider6d the

-Water Chemistry Control Program capable of managing loss of material in these components, particularly if the loss of material aging effect was determined to be induced by -mechanicaltype of aging mechanism, such as wear, erosion, fretting, or galling.

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I

In the applicant's response to RAI 3.1.3.1.2-1, part a, the applicant confirmed that the RV

internals upper core plate alignment pins, holddown springs, clevis inserts and fasteners, radial

support keys and fasteners, and flux detector thimble tubes were the RV internal components

that could potentially be subject to loss of material as a result of a mechanical-type of aging

mechanism. Further, wear was the aging mechanism that could induce loss of material in these

components. In response to RAI 3.1.3.1.2-1, part b, the applicant indicated that it would use

the Inservice Inspection Program to manage loss of material caused by wear in the RV internals

upper core plate alignment pins, holddown springs, clevis inserts and fasteners, and radial

support keys and fasteners. It would use the Flux Detector Thimble Tube Eddy Current

Program to manage loss of material resulting from wear in the flux detector thimble tubes.

Because the applicant is not crediting the Reactor Vessel Internals Program for managing loss

of material caused by wear in the RV internals upper core plate alignment pins, holddown

springs, clevis inserts and fasteners, radial support keys and fasteners, and flux detector

thimble tubes, the applicant has provided an acceptable basis for omitting loss of material due

to wear as an aging effectlaging mechanism that is within the scope of the AMP. The applicant

has identified that the following aging effects/aging mechanisms of concern are within the

scope of the AMP:

* cracking induced by IASCC

* loss of fracture toughness induced by neutron irradiation embrittlement, void swelling,

and thermal aging for cast austenitic stainless steel (CASS) RV internals

* changes in component physical dimensions as a result of void swelling

The staff finds this acceptable because these aging effects/aging mechanisms are identified in

GALL AMPs XI.M1 3 and XI.M1 6 as being applicable to RV internal components.

The applicant stated that scope of the Reactor Vessel Internals Program includes the following

RV internal components:

* baffle and former assemblies

* bottom-mounted instrumentation cruciforms (CASS)

* core barrel - '

* lower core plate and fuel alignment pins

* lower support forging

* rower support column bases

The staff determined that the list of components within the scope of the Reactor Vessel

Internals Program was not consistent with the list of components identified in LRA Table 3.1.2-2

for which the AMP was credited. The staff requested that the applicant modify the scope of the

Reactor Vessel Internals Program to make the list of components within the'scope of the AMP

consistent with the list of components for which the AMP is credited, as identified in Table 3.1.2-

2 of the LRA. The staff identified this issue in RAI B.5.1-2.

The applicant provided its response to RAI B.5.1-2 in its letter dated April 29, 2004 (SNC Letter

No. NL-04-0715).' In this resporise, the applicant clarified that the list of components within the

scope of the Reactor Vessel Internals Program is consistent with the list of RV internals in LRA

3-40
Table 3.1.2-2 for which the AMP is credited. The staff finds this acceptable because (1) the-.

applicant has clarified that the list of components within the scope bf the Reactor Vessel

Internals Program is consistent with the list of components in LRA Table 3.1.2-2 for which the

AMP is credited, and (2) the applicant's list of components within the scope of the program is

consistent with, and is at least as conservative, as the number of iRV internals components

listed in GALL.Section IV.B2, and managed by either GALL AMP Xl.M1 3, '"Thermal Aging and

Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel" and/or GALL AMP XI.M16,

"PWR Vessel Internals." --

Consistency with NUREG-1 801

GALLAMP XI.M16 provides the staff's recommendations for developing and implementing the

program attributes for PWR RV internals programs. In the LRA, the applicant stated that the

program is consistent with GALL AMPs XI.M16 and XI.M13, with certain exceptions. The

Reactor Vessel Internals Program is a new, integrated inspection program credited in the LRA

as an AMP for the aging effect of crack initiation and growth caused by IASCC,-Ioss of fracture

toughness due to irradiation embrittlement; thermal embrittlement or void swelling, or changes

in material properties as a result of void swelling. The program will supplement the RV internals

(core support structures) inspections required by the Inservice Inspection Program -During the

audit and review conducted from November 3 to November 7, 2003; the staff evaluated the;

applicant's claim of consistency. The FNP. Audit and Review Report documents the findings of

the FNP audit and review.-: Furthermore, the staff .reviewed the exceptions, and the applicant's

justification for those exceptions, to determine whether the AMP remains adequate to manage

:-the aging effects for which it is credited. The following paragraphs describe the staff's

evaluation of the exceptions taken by the applicant in the program attributes for the Reactor

Vessel Internal Program. , - -

Exceptions to NUREG-1 801

-In Appendix B.5.1 to the LRA, the applicant took an exception to the staff's recommendation of

augmented ultrasonic examinations of baffle bolt shafts. The applicant proposed instead to

perform VT.1 visual examinations in lieu of the augmented ultrasonic examinations

recommended in GALL AMP XI.M16 for baffle bolts. The applicant also stated that it will use its

participation in the EPRI Materials Reliability Project (MRP) studies and activities on PWR RV

internal components as the basis for determining which aging effects and mechanisms are

applicable to the RV internal components and which methods of examination- and frequency of

examinations are needed for these components.; Similarly, the applicant also took exception to

the Detection of Aging Effects program attribute and proposed to limit its VT-1 and enhanced

VT-1 examinations only to those locations suggested by indust research and operating

.1 The applicant provided the following definition of enhanced VT-1 examinations in the supplemental

response to RAI B.5.1-3 dated June 25, 2004 (refer to SNC Letter No. NL-04-1096):

-'For the FNP Reactor Vessel Intemals Program,'SNC intends to use the definition for:

Enhanced VT-1 (EVT-1) examination adopted by the EPRI Materials Reliability Program (MRP) Reactor Intemals Issue Task Group (RI-ITG). Currently, the EPRI Materials Reliability

Program RI-ITG definition is provided in MRP-99, 'Strategies for Managing Aging Effects in

PWR Vessel Internals-Interim Update." MRP-99 adopts the examination requirements of

BWRVIP-03, which describes EVT-1 as a visual examination method where the equipment

3-41
I

experience.

The staff believes that detection of cracking in baffle/former bolts is not possible by visual

techniques because cracking typically occurs at the bolt head/shank intersections, which are

not accessible for visual examination.2 In the staff's SE on WCAP-14577, Revision 1-A, -

"License Renewal Evaluation: Aging Management for Reactor Internals," dated March 2001,

the staff stated that ultrasonic examinations of the baffle/former bolt shafts should be used to

augment the visual examination techniques that are required for these components under

Section Xl of the ASME Code, Inspection Category B-N-3. The applicant will need to address

how it will manage cracking in the baffle bolts during the extended period of operation for FNP,

Units 1 and 2. The staff included resolution of this issue within the scope of RAI B.5.1-3. The

staff's discussion of the issues raised in RAI B.5.1-3 and the applicant's resolution of these

issues is provided later in this section.

The RV internals made from CASS include the BMI cruciforms and the upper support column

bases. In its SE on WCAP-14577, Revision 1, the staff stated that both thermal aging and

neutron irradiation embrittlement could lower the fracture toughness of CASS RV internals (i.e.,

as manifested in a reduction in the critical crack size for the CASS materials) and identified the

need for Westinghouse Owners Group (WOG)-member applicants to address the synergistic

impacts of thermal aging and'neutron irradiation'embrittlement on the fracture toughness

properties of their CASS RV intenals. The applicant did not-address this issue in LRA Section

B.5.1. The staff included resolution of this issue within the scope of RAI B.5.1-3.

The staff also determined that the applicant is using 1x1021 n/cm. (E t 0.1 MeV) as its threshold

values for initiation of neutron irradiation embrittlement in CASS RV internals and has identified

this as an exception from the program attributes for GALL AMP XI.M13. In comparison, GALL

AMP XI.M1 3 lists the threshold for the initiation of neutron irradiation embrittlement in CASS RV

internals as l x1 017 n/cm2 (E ; 1.0 MeV).

In WCAP-14577, Revision 1, the WOG stated that the neutron fluences for CASS lower support

castings will be less than 7x1 020 n/cm2 (E 2 0.1 MeV) through the expiration of the license

renewal period for Westinghouse-designed PWRs. Thus, given this low level of fluence,

neutron irradiation embrittlement should not be a concern for CASS RV internals found

acceptable by the WOG's screening criterion of lxi 021 n/cm2 (E t 0.1 MeV) for neutron

and environmental conditions are such that a 1

'A mil detection resolution can be demonstrated

against a neutral gray background. BWRVIP-03 demonstration protocols have been approved

by the NRC staff in a safety evaluation regarding BWRVIP-03 and approved for license

renewal in NUREG-1801, Section XI.M9, 'BWR Vessel Internals."

Additionally, as stated in our response to RAI B.5.1-3 in SNC Letter No. NL-04-0715 (dated April

29, 2004), the scope, Inspection requirements (inspection locations, methods, qualifications, and

frequencies), acceptance criteria, and corrective actions for the Reactor Vessel Intemals Program

will be based on the results 6f industry initiatives intended to clarify the nature and extent of aging

mechanisms potentially affecting the reactor vessel internals. Therefore, the examination methods

proposed, including the definition for EVT-1 examination, could change as a result of the industry

initiatives.

2 Refer to the staffs final safety evaluation report (FSER, dated February 10, 2000) on Westinghouse

Owners Group Topical Report WCAP-14577, Revision 1, 'License Renewal Evaluation: Aging

Management for Reactor Internals," dated October 2000.

3-42
irradiation embrittlement. However, in its SE on WCAP-1 4577, Revision 1; the staff did not

agree with the WOG's threshold for onset of neutron irradiation .eibrittlement in RV internal

components.' Th6'staff informed the WOG that for RV internal components fabricated from

CASS and hence subject to thermal aging and neutron irradiation embrittlement, exposure to

high operating temperatures and high neutron'fluences could have synergistic effects whereby

service-degraded fracture toughness is reduced from the levels predicted independently for

either of the mechanisms:. The staff thereford informed the WOG that renewal applicants for

Westinghouse-designed PWRs should describe their programs for managing aging in CASS

RV internals during the license renewal period (the staff identified this as Renewal Applicant

Action Item No. 6 in the SE of WCAP-14577, Revision 1).

The staff informed the applicant that it will need to address how it will manage cracking and loss

of fracture toughness caused by thermal aging or neutron irradiation embrittlement in the CASS

RV internals during the extended period of operation for FNP, Units 1 and 2, and justify the

difference in the neutron irradiation embrittlement threshold value assumed for the CASS RV

internals from that identified in GALL AMP Xl.Mi3. The staff included resolution of these

issues within the scope of RAI B.5.1 -3.

In Section IV.B2 of the GALL Report, the staff acknowledged that participation in the industry's

aging studies on PWR RV internal components (and specifically the industry initiative studies of

the EPRI MRP on PWR RV internals) may be used as an alternative basis for determining

exactly which types of inspections are'necessary for these components.

Because it has been adopted in the GALL Report, use of industry research studies and

activities on age-related degradation of PWR RV internal components may be cited as an

alternative basis for determining which age-related degradation mechanisms' are applicable to

PWR RV internals'and what types of examiinations are necessary to' manage these

mechanisms. This is a process-oriented approach to aging management that will ensure that

the inspections proposed for PWR RV internals are those that the industry research studies

have'demonstrated are necessary to' maintain the structural integrity or functionality of the

components. The NRC review of the recommended activities is an integral part of the industry

initiative process. ' '

However, any proposal to use the industry's research studies and activities on RV internals as

the basis for aging management must be coupled with (1) a commitment to implement the

recommendations that result from these' studies and activities, and (2) a commitment to submit

the inspictionr plan'fo'tdhe RV internals to'the NRC for review and approval before the period of

extended operation. The staff issued RAI B.5.1-3 to address this issue.

In its letter dated April 29, 2004 (SNC Letter No. NL-04-0715), the applicant provided its

response to RAI B.5.1-3. The response'included the following amended ve'rsion of tih6 program

description'for the Reactor Vessel Internals Program, as given in LRA Section B.5.1, and the

following amended version of the FSAR Supplement summary description for the' Reactor

Vessel Internals Program, as given in LRASe~ction'A.2.1 3: -

LRA Appendix B.5.1. Reactor Vessel Internals Program' Sections B.5.1.1 and B.5.1.3 should read as follows: ,_ . - ' . -. ; .

LRAAppendix B.5.1-Reactor Vessel Internals Program

:13-43
I

B.5.1.1 Program Description

The new FNP Reactor Vessel Internals Program will be an integrated inspection program that

addresses the reactor Internals (as identified in LRA Table 3.1.2-2). It is intended to supplement the

inspection requirements of ASME Section Xl, IWB Category B-N-3 to ensure that aging effects do not

result in a loss of intended function of internal components during the period of extended operation.

The Reactor Vessel Internals Inspection Program manages the effects of crack initiation and growth

due to irradiation assisted stress corrosion cracking; loss of fracture toughness due to irradiation

embrittlement, thermal embrittlement, or void swelling; or changes in material properties (dimension)

due to void swelling.-

SNC supports development of improved industry data, models, and inspection methodologies through

active participation in the EPRI Materials Reliability Program Reactor Vessel Internals Issue Task

Group and the Westinghouse Owners Group. SNC will continue to participate in industry initiatives

intended to clarify the nature and extent of aging mechanisms potentially affecting reactor vessel

internals. SNC will incorporate the results of these initiatives (to the extent that they are applicable to

the FNP reactor internals) into the scope, inspection requirements (inspection locations, methods,

qualifications, and frequencies), acceptance criteria, and corrective actions of the Reactor Vessel

Internals Program.

B.5.1.3 Exceptions to NUREG-1801

The scope, inspection requirements (inspection locations, methods, qualifications, and frequencies),

acceptance critera, and corrective actions will be based on the results of industry initiatives intended to

clarify the nature and extent of aging mechanisms potentially affecting the reactor vessel internals.

SNC will submit an inspection plan for the FNP Reactor Vessel Internals Program for NRC review and

approval at least 24 months prior to entering the periods of extended operation for the FNP units.

In its response to RAI B.5.1-3, the applicant clarified that the Reactor Vessel Internals Program

will incorporate a number of key elements to establish the capability of the AMP's program

attributes to manage aging in the FNP RV internal components. In particular, the applicant's

response clarifies the following four issues:

(1) The response clarifies that the applicant will use industry-wide research studies and

initiatives on age-related degradation of RV internal components to determine the

inspection methods, inspection method qualifications, inspection' frequencies, inspection

method acceptance criteria, and corrective actions for the Reactor Vessel Internals

Program.

(2) The response clarifies that the applicant will implement recommended inspection

activities, acceptarice criteria, and corrective actions that result from the industry's

studies and initiatives on age-related degradation of RV internals components, as the

recommendations apply to the design of the RV internals at the FNP units.

(3) The response clarifies that the applicant will submit an inspection plan for the FNP RV

internals for staff review and approval at least 2 years before entering the period of

extended operation f6r the FNP units. To obtain the NRC staff's approval of its

proposed inspection plan prior to the p6riod'of extended operation, the applicant must

submit a license amendment request. After the NRC staff's approval of the inspection

plan for the FNP RV internals, any future changes to the inspection plan will be

evaluated in accordance with the 10 CFR 50.59 process. The 2-year period will allow

the applicant and the staff sufficient time to resolve any issues with the inspection plan.

3-44
(4)_ The respornse' clarifies that the applicant will submit a comniitment to the staff

concerning the Rea'ctb Vessel Interials Program that reflects the three elements

discussed above.

The applicant's response to RAI B.5.1-3 also'included an amended version of the FSAR

Supplement summary descriptiori (i.e;, Sectio6 -AA2.13 of the LRA) for this AMP, which includes

a statement that the'applicant will make'a' comritment in the LRA that incorporates the three

elements discussed above. This commitment will provide the basis for determining the scope

and number of RV internals that are in need of examination, the type of examination methods

(i.e., ultrasonic, VT-1, or enhanced VT-i examrinatin methods) and frequency of examinations

required for managing cracking and other potential aging effects in the RV internals at FNP, the

methods that are needed to qualify the ability of the examination methods to detect.

degradation, and the acceptance criteria that will be used to assess the examination results.

The staff discusses this commitment furthe'rinfth-e FSAR Supplement for this AMP.

The EPRI MRP initiatives on the aging of PWR RV internals includes studies on managing the

cracking in baffle/former bolt materials and cracking and loss of fracture toughness properties

for RV internals made from CASS. The staff concludes that the applicant's LRA commitment is

acceptable because (1) it will apply acceptable industry guidelines that will ensure the use of

only those inspections that are capable of detecting degradation before a loss of component

intended function, (2) it will allow the staff to review the applicant's inspection plans for the RV

internals based on the industry recommendations, and (3) it will provide the staff an opportunity

to work with the applicant to resolve any potential issues with the inspection plan.

In the original program description for the Reactor Vessel Internals Program, the applicant also

indicated that it was taking an exception on the'number of examination cycles set forth in

Section Xl of the ASME Code, Subsection IWB, for RV internal components. The staff

informed the applicant that it must submit this exception for review'and approval, in accordance

with 10 CFR 50.55a. The staff requested that the applicant withdraw this exception from the

application and cormniit to following the ASME Code, unless specific relief is granted under the

relief request or alternative program provisions of 10 CFR 50.55a. The staff identified this as

RAI B.5.1-4.

The applicant provided its response to RAI B.5.1-4 dated April 29, 2004 (SNC Letter No. NL04-0715). In this.response, the applicant clarified that it was not taking exception to the number

of examination cycles set forth in Section Xlof the*ASME Code,'Subsection IWB, for inspection

of RV internal components required under the FNP Inservice Inspection Program. The staff

concludes that this is acceptable because it indicates that the applicant will continue to comply

with 10 CFR 50.55a, unless specific relief is requested and granted on a given RV internal ISIrequirement. The applicant also clarified that, for the augmented examinations that would be.

implemented as part of the Reactor Vessel Intemals.Program, the examination frequencies

would be based on those recommended by the industry's initiatives on RV internal components.

This is acceptable because it reflects the revision to the program previously discussed and

accepted by the staff.- . - .

FSAR Supplement -.

In Section A.2.13 of Appendix A to the LRA, the applicant provided the FSAR Supplement for

the Reactor Vessels Internals Program. The staff reviewed this section of the LRA and

; 3-45
informed the applicant that it must update the summary description in Section A.2.13 of the

LRA to reflect information that will be provided in the applicant's response to RAI B.5.1-3. This

request was included within the scope of RAI B.5.1-3.

In its letter dated April 29, 2004 (SNC Letter No. NL-04-0715), the applicant provided its

response to RAI B.5.1-3. The response included the following amended version of the FSAR

Supplement summary description for the Reactor Vessel Internals Program, as given in LRA

Section A.2.13:

To address the staffs issues, SNC will revise the LRA FNP UFSAR Supplement A.2.13 to read as

follows:

A.2.13 REACTOR VESSEL INTERNALS PROGRAM

The new FNP Reactor Vessel Internals Program will be implemented prior to entering the

period of extended operation to provide an integrated inspection program that addresses

the reactor intemals. It will be governed by administrative controls and procedures to

supplement the inspection requirements of ASME Section Xl, IWB Category B-N-3 to

ensure that aging effects do not result in a loss of intended function of internal

components during the period of extended operation.

The program will be used during the period of extended operation to manage the effects

of crack initiation and growth due to irradiation assisted stress corrosion cracking; loss of

fracture toughness due to Irradiation embrittlement, thermal embrittlement, or void

swelling; or changes in material properties (dimension) due to void swelling.

SNC will continue to participate in industry initiatives intended to clarify the nature and

extent of aging mechanisms potentially affecting reactor vessel internals. SNC will

incorporate the results of these initiatives (to the extent that they are applicable to the

FNP reactor internals) into the scope, inspection requirements (inspection locations,

methods, qualifications, and frequencies), acceptance criteria, and corrective actions of

the Reactor Vessel Intemals Program.

SNC will submit an inspection plan for the FNP Reactor Vessel Intemals Program for

NRC review and approval at least 24 months prior to entering the periods of extended

operation for the FNP units.

The FNP Reactor Vessel Internals Program is consistent with the 10 attributes of the

aging management program described in NUREG-1 801, Sections XI.M1 3 and XI.M1 6,

except as described above.

The 'Farley Nuclear Plant-Ucense Renewal Future Action Commitmenr list will be

revised accordingly.

The applicant's response to RAI B.5.1-3, as it pertains to the FSAR Supplement summary

description for the Reactor Vessel Internals Program, clarifies that the program will incorporate

a number of key elements to establish the capability of the AMP's program attributes to manage

aging in the FNP RV internal components. Specifically, the applicant clarified the following four

issues:

(1) The response clarifies that the applicant will use industrywide research studies and

initiatives on age-related degradation of RV internal components to determine the

inspection methods, inspection method qualifications, inspection frequencies, inspection

method acceptance criteria, and corrective actions for the Reactor Vessel Intemals

Program.

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(2) The response clarifies that the applicant will implement recommended inspection

activities, acceptance criteria, and corrective actions that result from the industry's

studies and initiatives on age-related degradation of RV internals components, as the

recommendations apply to the design of the RV internals at the FNP units.

(3) The response clarifies that the applicant will siubmit an inspection plan for the FNP RV

internals for staff review and approval at'least 2 years before entering the period of

extended opieration for the FNP units. The 2-year period will allow the applicant and the

staff sufficient time to resolve any issues with the inspection plan.

(4) The response clarifies'that the applicant will sibmit'a commitment to the staff

concerming the Reactor Vessel Internals Program that reflects the three elements

discuss6d above.

In the staff's evaluation section associated with this AMP, the staff provided its basis for

accepting the applicant's process for monitoring and trending age-related degradation in the

FNP RV internals.' The staff concludes that the FSAR Supplement summary description for the

Reactor Vessel Intern'als Program, as amended in the applicant's letter dated April 29, 2004

(SNC Letter No. NL-04-0715), is acceptable because it reflects the revision to the program and

process for the RV internals, which the staff found acceptable, as documented in Section

3.0.3.2.7 of this SER. In addition, the applicant's response reflects that it will make a

commitment regarding the AMP which incorporates the'key elements for the program and

process that'the staff found to-be acceptable.-''

Conclusion - - '

On the basis of its review and audit of the applicant's program, the staff finds that thosei---

attributes of the program for which the applicant claimed consistency with the GALL Report are.

indeed consistent with GALL. 'The staff finds that the applicant has demonstrated that the,

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of exteided operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the FSAR Supplement for this AMP and finds that it

provides an adequate summary description 6f th6 program, as required by 10 CFR 54.21 (d)...

3.0.3.2.8 Non-EQ Electrical Cables Used in'Instrumentation Circuits

Summary of Technical Information in the Application' -

Section B.5.6.1 ;"N6W;EQ Electrical Cables Used in' Instrumentation Circuits," of the LRA

describes the non-EQ electrical cables used in instrumentation circuits. The applicant stated

that the program for non-EQ electrical cables'used in instrumentation circuits are consistent

with GALL AMP XI.E2, uElectrical Cables Not Subject To 10 CFR 50.49 Environmental -*

Qualificatio 'Requirem'ents Used In In'strurmientation'Circuits," with an exception. ; ;

The applicant stated that the Non-EQ Cables' Program is a new inspection and testing program

that will be iriIplemented before the peridd of extended operation-'It will be used to maintain

the function of electrical cables whichrae not subject'to the environmental qualification,(EQ) .-

requirements of 10 CFR 50.49, but are exposed to adverse localized environments caused by

h6at, radiation, or noisture. The applicant cbnsidered ISG-15 in preparation of the attributes of

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this new program.

Staff Evaluation

During its audit and review, the staff confirmed the applicant's claim of consistency with the

GALL Report. The FNP Audit and Review Report documents the FNP audit findings and

conclusions. Furthermore, the staff reviewed the exception and its justification to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited.

The aspect of the applicant's Non-EQ Cables Program described in Section B.5.6.1 of the LRA

is consistent with GALL AMP XL.E2, with the exception that the applicant will incorporate

program details applicable to the specific types of cables within the scope of the program, in

accordance with the alternate XL.E2 program developed by the License Renewal Electrical

Working Group.

The staff observed a typographical error in Section 5.6.1.1 of the LRA. Specifically, the

applicant referenced ISG-5 instead of ISG-1 5. In its letter dated December 5, 2003, the

applicant stated that the correct reference is ISG-1 5.

In Sections 5.6.1.5 and 5.6.1.6 of Appendix B to the LRA, the Parameters Inspected or

Monitored and the Detection of Aging Effects program attributes stipulated, in part that, "A

representative sample of instrument circuit cables with sensitive, high-voltage, low-level signals

which are installed in adverse localized environments will be tested...." GALL AMP XI.E2 and

ISG-15 do not stipulate the use of sampling. The staff noted that the number of cables in this

category is comparatively small (e.g., ex-core nuclear instrumentation cable). To address this

difference, the applicant stated that it will revise the Parameters Monitored or Inspected and

Detection of Aging Effects program attributes to test all cables in the alternate XL.E2 program,

rather than a sample.

The applicant issued a supplement to the LRA dated December 5, 2003 (SNC Letter No. NL03-2418), Enclosure 1, to address this issue. The applicant stated that sampling will be

removed from the alternate XL.E2 program and that it will test all cables.. During the audit and

review conducted at the applicant's headquarters office from December 15 to December 19,

2003, the staff determined that the applicant had revised the AMP master document.

In Section 5.6.1.8 of Appendix B to the LRA, the Acceptance Criteria program element and the

AMP program documentation differ from GALL AMP XL.E2 and proposed ISG-15, which

stipulate that calibration results or findings of surveillances are to be within the acceptance

criteria, as set out in the surveillance procedures. The LRA and AMP acceptance criteria did

not specify the use of calibration and surveillance testing, and excluded it in the AMP Operating

Experience' section, which stated in part, that "Testing of cables that have been exposed to heat

and radiation can provide a possible indication of potential electrical cable degradation. This

differs from NUREG 1801, Section XL.E2 use of operating experience in that changes in

instrument calibration are not used." The applicant stated that nuclear instrumentation circuits

would be tested because the instruments are calibrated with the cables disconnected. Cable

testing is a more desirable approach for this application because the calibration results would

provide minimal information about the cables. The applicant issued a supplement to the LRA

dated December 5, 2003 (SNC Letter No. NL-03-2418), Enclosure 1, to address this issue. In

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the response to Question E30, the applicant r6sated why it used the alternate XL.E2 program.

'The staff concludes that because the cables are adisca

because the 'applicant agreed t6 test all cables t ection to use the alibrate 'and

program'is acceptable. - - - t ei ' t u -t a 'E'

During the audit and review, the staff requested the applicant to clarify how it considered nonEQ containment electrical 'pen'etrations. Tabie4i4o6f the LRA, "List of EQ Packages," describes

specific. EQ packages. 'However, it was n6t 'evident that containment electrical penetrations

were included in the'table, and no AMP wasl' edited foi containnient electrical penetrations.

By letter dated December 5, 2003 (SNC Letter No. NL-03-2418), the applicant stated that FNP

has both EQ and non-EQ containment electrical penetrations. The pressure boundary function

of both EQ and non-EQ electrical penetrations is covered under the Inservice Inspection

Program.! The Non-EQ Cables Programr covers'the6electrical''portions of the penetrations'that

provide'a'cohnection function for nonsafety-re ated equipment. ' -

On the basis of its review of this AMP, the associated program master document, the relevant

station administrative procedure, and a sample of implementing procedures, the staff

determined that this AMP is consistent with the GALL Report, and that the exception to the' n&nEQ electrical cables used in instrumentation circuits is acceptable.

Operating Experience' '' ' * ,; . :

The applicant stated in'the Operating Experie'nce section of FNP AMP B. 5.6.1 that this program

is a new program" with no operating experience history. However, the applicant will use

effective'and proven testing'techniiques for this new programr. Furthdrrnore, the applicant will

consider lessons learned during the perforrmanc6e of this program,radditional industry

experience, and other testing techniqu'es de'v'eloped in the industry.

The applicant stated, in the FNP LRA, that industry operating experience has shown that

exposure to heat and radiation results in the degradation of insulating materials. Testing of

cables that have been exposed to heat and radiation can provide'a'possible indication of

potential electrical cable degradation. In addition to industry operating experience, the

applicant investigated the operating history f6r in-scope electrical components using condition

report searches, internal correspondence, platntXWlkdowns, and interviews.'

The Operating Experience program ele'6rifnt crit6ria in GALL AMP'XI.E2 state that operating

experience'has shown that a signifiicant'umber' f cable'faildres are identified through routine

calibration testing. Changes in instrument calibration can be caused by'degradation of the

circuit cable and are one indication of potential electrical cable degradation.

.;- :tc?_P ,'-: ' ,-? .

Furthermore, in ISG-1 5, the operating experience' discussion states that'the'vast majority of

site-specific and iridustrywide' operating experiex..e..garding neutron flux instrumentation

circuits is related to cable/conn'e'ct'or'is'su'e's inside of the containment near the reactor.vessel.

There is'comparatively`far less operating 'experieri6e in'other, mord benign areas of the plant.:

During the audit, the staff noted that connectors were included in the Operating Experience

attribute of ISG-15, but not in FNP AMP B.5.6.1. To clarify this, the applicant stated that

connectors were included in GALL AMP XI.E2, anrd thbat it will revise the FNP AMP B.5.6.1 to

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I a

include the draft ISG-15 wording for this attribute. By letter dated December 5, 2003,(SNC

Letter No. NL-03-2418), the applicant submitted a supplement to the FNP LRA. In its response,

the applicant agreed to revise its AMP master document to incorporate this wording. The staff

reviewed and confirmed that the applicant's AMP master document had been revised and found

it to be acceptable.

On the basis of its review of the above operating experience and discussions with the

applicant's technical staff, the staff concludes that the non-EQ electrical cables used in

instrumentation circuits adequately manages the aging effects that have been observed at

FNP.

FSAR Supplement

In Appendix A.2.19 to the LRA, the applicant provided the FSAR Supplement for the Non-EQ

Cables Program. The staff reviewed this section and determined that the information in the

FSAR Supplement provides an adequate summary of the program activities. The staff finds

this section of the FSAR Supplement sufficient.

Conclusion

On the basis of its audit and review 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 GALL. In addition, the staff reviewed the exceptions to the GALL Report

program and finds that the applicant has demonstrated that the effects of, aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the FSAR Supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.9 Flow-Accelerated Corrosion Program

Summary of Technical Information in the ADplication

Section B.4.1, "Flow Accelerated Corrosion Program," of the LRA describes the applicant's

Flow-Accelerated Corrosion Program. The applicant stated that the program is consistent with

GALL AMP XI.M17, -Flow Accelerated Corrosion," with an enhancement. This AMP is credited

for managing loss of material due to flow-accelerated corrosion (FAC) for specific

component/commodity groups in the auxiliary steam and condensate, feedwater, main steam,

and SG blowdown systems.

By letter dated July 27, 2004, the applicant provided an LRA supplement to the FAC Program.

The applicant states that under the FAC Program, it has elected to replace some carbon steel

piping and piping components with FAC-resistant chrome-molybdenum alloy steels. This is an

on-going activity which recently resulted in alloy steel replacements in portions of

FAC-susceptible systems that are in-scope for license renewal. Although the alloy steel has

increased the resistance to flow-accelerated corrosion, the alloy steel components remain in the

scope of the FAC program.

The applicant stated that its aging management review for alloy steels in FAC-susceptible

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system's concludes that the aging 'effects requiring 'management are conservatively bounded by

those applicable to carbon steel components. The aging managemient programs applied to the

carbon steel components are also applicable to the alloy steel components.

In lieu of adding new comnponent/material 6ombinations,'the carbon steel material type in the

aging management review summary tables for'FAC-susceptible systems is defined to include

FAC-resistance alloy steels.

Staff Evaluation '

During its audit and review, the staff confirmed the applicant's-claim of consistency with the

'GALL Report. :The' FNP Audit and Review Report document the FNP audit findings and,

conclusions. Furthermore, the staff reviewed the enhancement and its justification to determine

whether the AMP, with the enhancement, remains adequate to manage the aging effects for

which it is credited. -.

The applicant has determined that the replacement SG steam nozzles are not FAC susceptible.

The SG nozzle material is not carbon steel, but alloy steel. The staff requested the applicant to

provide the material information for the feedwater inlet and main steam outlet nozzles. By letter

dated August 19, 2004, the applicant provided its supplemental information to the LRA. In its

response, the 'aplicant stated that the alloy material specification applicable to the replacement

SG feedwater inlet-and main steam outlet nozzles is ASME SA-508 Class 3 alloy steel material

which provides' increased resistance'to FAC as corripared to carbon steel. I Upon this basis, --

Item D1.1.2 of GALL IV D1-3, listed'only carbon steel 'material as requiring management under

this combination of environment and aging mechanism. The staff concludes that the applicant's

determination, that the SG feedwater and main steam nozzles are not FAC susceptible, is

consistent with GALL and finds it acceptable.

The applicant stated, in Appendix B to the LRA, that there are differences between the scope of

the Flow-Accel6rated Corrosion Program' and the scope of GALL AMP Xl.M1 7. To address the

scope differences; the applicant stated that the -scope of the FAC program will be enhanced to

include the AFW pump turbine exhaust piping before the period of extended operation. The

staff determined that this enhancerhenit is acceptable because'any such changes will provide

additional assurance that the effects of aging will be adequately managed. The applicant

addressed this enhancement in Appendix A, FSAR Supplement, under A.2.8, Flow Accelerated

Corrosion Program, of the LRA. In addition, by letter dated July 27, 2004, the applicant

included this enhancement as a commitment in'its FNP-License Renewal Future Action

Commitments.

On the basis of its review of this AMP, the associated program master document, the relevant

station administrative procedure, and a sample of implementing procedures; the staff z

determined that th' Flow-Accelerated Corr6siohnProgram'is consistent with the GALL Report,

and that the programrenhancement is'acceptable. -

Operating Experience ' -

The applicant stated in the LRA that operating experience shows that a properly implemented

flow-accelerated corrosion program is effective in managing FAC in high-energy carbon steel

piping and components. The applicant stated that the NRC inspection reports have consistently

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N

reported that the applicant's program is effective in maintaining high-energy carbon steel piping

within acceptable wall thickness limits.

In addition, the applicant stated that it captured recent operating history when its engineering

support department compared the plant-specific FAC operating experience for the feedwater

system against NRC IN 2001-09, "Main Feedwater System Degradation in Safety-Related

ASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor." Through

1 R17 (Fall 2001), 74 points in the Unit 1 feedwater system had been examined. Through

2R1 5 (Fall 2002), 82 points in the Unit 2 feedwater system had been examined. Based upon

recent examinations, the applicant had scheduled approximately eight components for

replacement on Unit 1 during 1 Ri 8, and recommended approximately 25 feet of piping in the

turbine building and one component in the main steam valve room for replacement during 2R16

for Unit 2.

Based on its review of the above operating experience, the staff concludes that the FlowAccelerated Corrosion Program adequately manages the aging effects that have been

observed at FNP.

FSAR Supplement

In Appendix A.2.8 to the LRA, the applicant provided the FSAR Supplement for the FlowAccelerated Corrosion Program. The staff reviewed this section and determined that the

information in the FSAR Supplement provides an adequate summary of the program activities.

The staff finds this section of the FSAR Supplement sufficient.

Conclusion

On the basis of its audit and review 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 GALL In addition, the staff reviewed the enhancement to the GALL

Report program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the FSAR Supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.10 Buried Piping and Tank Inspection Program

Summary of Technical Information in the Application

The applicant's buried piping and tank inspection program is described in AMP B.5.4, Buried

Piping and Tank Inspection Program' of the LRA. The applicant stated that the program is a

new program that will be initiated prior to the period of extended operation. The applicant

stated that the program will be consistent with GALL AMP XI.M34, "Buried Piping and Tanks

Inspection." By letters dated April 7, 2004 as revised by March 3, 2005 letter, February 24,

2005, and February 25, 2005, the applicant updated its AMP B.5.4 to be consistent with GALL

AMP XL.M34 with exceptions.

The applicant stated that its Buried Piping and Tank Inspection Program will be used to

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.i
manage the loss of material from the external surfaces of pressure-retaining buried carbon

steel pip ing and tanks.: 'Preventive measures'have been put in place in accordance with

standard industry practices for external coatings and wrappings. By letter dated April 7, 2004-

as revised by March 3, 2005 letter, the applicant updated its program to include buried stainless

steel and copper alloy piping components in the program scope. Also, by letters dated

February 24, 2005 and February 25,72005,;theeapplicant stated that buried piping and tanks will

be inspected within ten yVears'after entering the period of extended operation, unless an

opportunistic inspection has occurred withiri this ten-year period.' Prior to the tenth year, the

applicant 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 and tanks from degradation"'if not, the applicant will conduct a focused

inspection to allow that conclusion to be reached. - : _4 ; ;I .,, _...,,, ' ,; 4., _',- -',,''! , _

Staff Evaluation - ..

During its au'dit'and review,'the staff verified the applicant's claim of consistency with the GALL

Re ort." The audit findings and conclusions are'documented in the FNP Audit and Review

Report: Furthermorei'the staff reviewed the exceptions and the applicant's justification to -

determine whether the AMP, with the exceptions;- remains adequate to manage the aging effects'for which it is credited. : ;: i* - - ->

_' . . , * e;- ;

In its April 7, 2004 letter as revised by its March 3, 2005 letter, the applicant stated that it takes

exception to the scope of the buried piping and tank inspection program in that the new buried

piping'and tank inspection program will -also be used to manage the loss of material from the - external surface of -in-scop'e buried stainless steel 'and copper alloy piping during the period of

extended operation. The staff reviewed the applicant's operating experience with respect to

loss of material caused by corrosion of external surfaces of buried stainless steel and copper

alloy piping and finds that stainless steel and copper alloy material are resistant to corrosion in

a buried environment. On the basis of its review of operating experience and material

environment combinations; the staff finds this exception to be acceptable. ;, * ,- - 4.4 * s

The applicant also takes exception to the 'detection of aging effects program element in that the

buried tanks and piping inspections are performed when the components are excavated for

maintenance or for any other reason including investigation of a potential leak. By letters dated

February 24, 2005 (SNC Letter No. NL-05-0340) and February 25, 2005 (SNC Letter No.

NL-05-0366), the applicant provided LRA supplement. .In its LRA supplement, the applicantstated that the'buried piping and tanks will be inspected within ten years after entering the - -

'periodof extended operation, unless an opportunistic inspection has occurred within this

ten-year period. Prior to the tenth year,rthe applicant 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 and tanks from

degradation. If not, the applicant will conduct a focused inspection to allow that conclusion tobe reached. - + _4 -- i 4;'1

The staff reviewed the applicadnt's operating experience with excavations over the past few

years, together with applicant's letter dated April 7,-2004, and as revised by its letters dated'

February 24, 2005, Febr'uary 25, 2005, and March 3, 2005; and finds that the frequency of

excavating buried components for maintenance activities will be sufficient such that the effects

of aging will be identified prior to the loss of intended function. Problems discovered in piping,

.3-53
I I

requiring evaluation and reporting under the plant's corrective action program, may necessitate

expanding the inspection scope. Excavating such components solely to perform inspections

could pose an undue risk of damage to protective coatings. On the basis of its review, the staff

finds this exception to be acceptable.

In its April 7, 2004 letter, and as revised by its March 3,,2005 letter, the applicant took an

exception to the parameters monitored/inspected program element in that for

uncoated/unwrapped piping,-visual inspection will also be used to examine the external

surfaces to confirm that no loss of material has occurred. The staff reviewed the applicant's

exception, which applies to typically uncoated and unwrapped stainless steel and copper alloy

piping, as well as the operating experience with excavations for copper alloy and stainless steel

piping, and finds no instances of corrosion on the piping of these materials. On the basis of its

review of applicant's operating experience and the materials' resistance to corrosion in a buried

environment, the staff finds this exception to be acceptable.

Also, in its April 7, 2004 letter, and as revised by its March 3, 2005 letter, the applicant took an

exception to the acceptance criteria program element in that any loss of material in piping will

also be reported and evaluated according to site corrective action procedures. The staff.

reviewed the applicant's exception, which applies typically to uncoated and unwrapped buried

stainless steel and copper alloy piping in the open-cycle cooling water and fire protection

systems, and the applicant's operating experience, and on the basis of its review, the staff finds

this exception to- be acceptable.

On the basis of its review of the applicant's letters dated April 7, 2004, and as revised by its

letters dated February 24, 2005, February 25,2005, and March 3, 2005, the staff finds that the

applicant's exceptions to the GALL AMP XL.M34 to be acceptable.

Operating Experience .

The applicant stated in the LRA that for the operating experience program element, the buried

piping and tank inspection program is a new program. Therefore, no programmatic operating

experience has been gained. However, the applicant will take into account, during the

extended period of operation, lesson learned from performance of this program to confirm its

effectiveness.

The staff reviewed the applicant's information related to buried piping and tanks. The staff

recognizes that the corrective action program, which captures internal and external plant

operating experience issues, will enable 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.

FSAR Supplement

In Section A.2.16 of the LRA, the applicant provided the FSAR Supplement for the Buried

Piping and Tank Inspection Program. By letter dated April 7, 2004, the applicant updated its -

FSAR Supplement to include buried stainless steel and copper alloy piping components in the

program scope. By letter dated February 25, 2005, the applicant clarified its FASR Supplement

commitment to the buried piping and tank inspection program. The staff reviewed this

commitment and determined that the information in the FSAR supplement commitment

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provides an adequate summary 6f ihe program'actiiAs.' The staff finds this FSAR supplement

commitment sufficient. ' -

Conclusion

On the basis of its audit and review of the applicant's program,' the staff finds that those

attributes of the program for which the applicant claimed consistency with the GALL Report

program are consistent with'ihe GALL Report prograim. In' addition,- th6 staff r'eview6d the

exceptions to the GALL Report program and firids that the applicarit has .dem6fnstrated 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 ext6nded 6peration, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the FSAR supplement for this AMP and finds that it

provides an adequate summary descriptionbof the program, as required by 10 CFR 54.21 (d).

-30.3.2 11 Summary of Conclusion for AMPs That Are Consistent with the GALL Report, but

with Exceptions and/or Enhnricements ' i i

On the basis of its review and audit of the applicant's AMPs, the'staff concludes that for the

AMPs listed above, the applicant has demonstrated that the effects of aging will be adequately

managed so that the in'tended fu'nctionis'will be rmraintained consistent 'with the CLB for the

period of extended operation, as required byl O1CFR 54.21 (a)(3).' The staff reviewed the

associated FSAR Supplements for these'AMPs and 'concludes that the FSAR Supplemnents

provide an adequate summary description of the programs, 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 were plarit-specific:

* Flux Detector Thimble Inspection Prograim (B.5.2)

* -External Surfaces Monitoring Program'(B.5.3) -

* NiCrFe Component Assessment Pri'bramii '(B.5.8) * Periodic Surveillance and Preventive Maintenance Activities (B.5.9)

For AMPs that are not consistent with or not addressed by the GALL Report, the staff

performed a 6omplete revie'w-of the AMPs t deterimine if they-were adequate to monitor or

manage aging. The following section 'docur'neht the staff's review of these plant-specific

AMPs.

3.0.3.3.1 Flux Detector Thimble'Inspectioh Program

The staff's regulatory basis for &stablishing the applicant's Flux Detector Thimble Inspection

Program is given in NRC BL 88-09, "Thimble Tube Thinning in Westinghouse Reactors," dated

July 26,.1988, which was addressed toall'h old6'r-sof operating licensesor construction permits

for Westinghouse.-designed nitcletar re'actors" that utilize' Bottom Modnted Instrumentation (BMI)

nozzles. In this bulletin, the staff requested, in part, that each licensee addressed by the'

bulletin establish an inspection program for flux detector thimble tubes (henceforth referred to

as 'thimble tubes") with the following three programf attribute-:

(1) The establishment, with technical justification, of an appropriate thimble tube wear

3-55
1.

acceptance criterion (e.g., based on percent through-wall loss). The staff recommended

that the acceptance criterion include allowances for such items as inspection

methodology and wear scar geometry uncertainties.

(2) The establishment, with technical justification, of an appropriate inspection frequency

(e.g., every refueling outage).

(3) The establishment of an inspection methodology that is capable of adequately detecting

wear of the thimble tubes (e.g, eddy current testing).

Summary of Technical Information in the Application

In Section B.5.2 of Appendix B to the LRA, the applicant stated that the Flux Detector Thimble

Inspection Program will be a formalization of the examination process currently performed at

FNP, Units 1 and 2. The applicant implemented the current examination process in response to

BL 88-09. The new Flux Detector Thimble Inspection Program will be used to identify loss of

material resulting from fretting/wear in the thimble tubes during the periods of extended

operation for FNP, Units 1 and 2.

The applicant's response to NRC BL 88-09, "Joseph M. Farley Nuclear Plant-,-Units 1 and 2,

Thimble Tube Thinning in Westinghouse Reactors, NRC Bulletin 88-09," dated November 2,

1988, provides additional information regarding the Flux Detector Thimble Inspection Program.

Staff Evaluation

In Section B.5.2 of Appendix B to the LRA, the applicant described the Corrective Actions,

Confirmation Process, and Administrative Controls program elements. Section 3.0.4 of this

SER provides a separate evaluation of these three program elements. The remaining elements

are evaluated below. The staff also included the applicant's response to NRC BL 88-09 within

the scope of its evaluation. The staff also referred to information contained in the staff's

January 12, 1990, BL 88-09 audit report, which documented the staff's followup audit on the

applicant's BL 88-09 response.

[Program Scope] In Section B.5.2.3 of Appendix B to the LRA, the applicant stated that the

Flux Detector Thimble Inspection Program will include the thimble tubes for both units. It does

not include the instrument guide tubes, which are covered by the Inservice Inspection Program

and the Reactor Vessel Internals Program.

In its response to BL 88-09, the applicant indicated that it had performed ECT inspections of.,

100 percent of the thimble tubes at FNP, Unit 1, during refueling outages (RFOs) 7 and 8 and

at FNP, Unit 2, during RFO 5. The applicant's BL 88-09 response did not indicate whether the

applicant would continue to perform 100 percent inspections of the thimble tubes during

subsequent RFOs. The staff requested the applicant clarify whether it intended to continue to

include ECT of 100 percent of the thimble tubes within the scope of the Flux Detector Thimble

Inspection Program. The staff identified this request as RAI B.5.2-1.

The applicant provided the following response to RAI B.5.2-1 in its letter dated April 16, 2004

(SNC Letter No. NL-04-0617):

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All accessible flux thimble tubes are inspected uing ECT at each scheduled inspection. Flux

thimble tubes which have been previously capped, or.which are obstructed, cannot be inspected.

The flux thimble tubes are inspected over their full length from the seal table to the nose of the

tube at the top of the core. SNC will continue to inspect all accessible flux thimble tubes at each

scheduled inspection. See the response to RAI B.52-3 to address scheduling of these

inspections.

In SNC Serial Letter No. NL-04-1396, dated August 5, 2004, the applicant provided a

supplemental response to RAI B.5.2-1. Inithis supplermnent response, the applicant clarified that

any thimble tube which is inaccessible for examiriatioh will be capped. Capping will prevent any

potential through-wall leakage from tubes thatannbot be examined. Since this will address any

pressure boundary, integrity issues in thimble tubes that cannot be examined, RAI B.5.2-1 is

resolved and the applicant's Program Scopeqprogram attribute for the Flux Detector Thimble

Inspection Program is acceptable. - !

[Preventive Actions] In Section B.5.2.4 of Ap'pendix B to the LRA, the applicant stated that no

preventive actions are associated with this monitorin'g program. The staff determined that the

Flux Detector Thimble Inspection Program is an inspection-based condition monitoring program

and that, as such, the program does not inlude evntive or mitidative'actions to preclude the

occurrence of an aging effect. On the basis of this determrination,'the staff concludes that the,

Preventive Actions program attribute is acceptable. i.

[Parameters Inspected or Monitored] In Section B.5.2.5 of Appendix B to the LRA,'the

applicant stated that it will conduct wall thickness measurements to detect loss of material from

the flux detector thimbles. ln its response to'NRC BL' 88-09, the applicant stated that the ECT

vendor developed a calibration standard t6 include American Society of Mechanical Engineers

(ASME) Boiler and Pressure Vessel Code staridard defects, typical wear patterns, and service

defects. Because ECT is a standard -NDE technique that is appropriate for the detection of

wear, the staff concludes that the applicant's Parameter Irn'spected or Monitored program

attribute is acceptable.

[Detection of Aging Effects] In Section 5.2.6 of Appendix B to the LRA, the applicant stated that

ECT or other suitable examination methods will be used to detect loss of material from flux -

detector thimbles. In its response to NRC BL 88-09, the applicant stated it began performing

ECT of the thimble tubes at FNP in 1986. The staff determined that the use of ECT is

consistent with the inspection methodology specified in NRC BL 88-09. In its BL 88-09 audit

report issued January 12, 1990,'the staff concluded th1at the Flux Detector Thimble Inspection

Program used acceptable inspection methods with technically justifiable acceptance criteria.

However, the applicant's AMP description for the Flux Detector Thimble Inspection Program

implies that the applicant may use alternative inspections to ECT. The staff requested that, if

other inspection methods are used in lieu of ECT, the applicant clarify which alternative

inspection methods it will use for the thimble tube examinations and how the alternative

inspection methods, if used, will be qualified as being capable of detecting loss of materiaVwear

in the thimble tubes. The staff identified this request as RAI B-1.

The applicant provided the following response to RAI B-i in a letter dated April 16, 2004 (SNC

Letter No. NL-04-0617): ' i 

Eddy current testing (ECT) is the technique currently used to determine the amount of wear on flux

thimble tubes. Other volumetric examination techniques are not currently credited as alternatives

.3-57
to eddy current testing. If other volumetric examination techniques become available in the future,

SNC reserves the option to revise the Flux Detector Thimble Inspection Program to perform inspections using qualified techniques. SNC will continue to participate in Westinghouse Owner's

Group (WOG) activities related to flux detector thimble inspection. When issued, any WOG

recommended actions, including changes to qualified inspection methods, will be reviewed and the

Flux Detector Thimble Inspection Program modified, as appropriate. This is consistent with the

November 2, 1988 response to NRC Bulletin 88-09 for FNP.

The applicant's response clarifies that ECT is the normal inspection method used for these

examinations and confirmed that only ECT will be used as the method for the examinations,

unless other acceptably qualified volumetric examination techniques are proposed by'the WOG

for inspecting the thimble tubes. To date, the applicant uses ECT as the qualified technique

for inspecting the thimble tubes. The staff recommended this acceptable technique in NRC BL

88-09. Because the applicant will use only acceptably qualified volumetric examination

techniques to detect wear in the thimble tubes, the staff concludes that the applicant has

proposed acceptable inspection methods for managing this aging effect and that the Detection

of Aging Effects program attribute is acceptable. Therefore, RAI B-1 is resolved.

[Monitoring and Trending]. In Section 5.2.7 of Appendix B to the LRA, the applicant stated that

it will trend ECT results and calculate wear rates. Wear predictions will dictate the examination

frequency. In its response to NRC BL'88-09, dated November 2, 1988, the applicant stated

that the program will include ECT at each RFO until it establishes adequate confidence in wear

rate projections. In its BL 88-09 audit report issued on January 12, 1990, the staff stated that

the inspection frequency of every RFO is acceptable. However, during the LRA audit of

November 3-7, 2003, the staff determined that the applicant is basing its implementation of the

Flux Detector Thimble Inspection Program on WCAP-128663, uBottom' Mounted Instrument

Flux Thimble Wear," dated January 11, 1991. The staff requested confirmation that WCAP12866 does not change the inspection frequency for the Flux Detector Thimble Inspection

Program from that approved in the BL 88-09 audit report of January 12, 1990. The staff

identified this request as RAI B.5.2-3

The applicant provided the following response to RAI B.5.2-3 in its letter dated April 16, 2004

(SNC Letter No. NL-04-0617):

In the November 2, 1988 response to NRC Bulletin 88-09 for FNP, Alabama Power Company stated 'Alabama Power Company will continue to monitor thimble tube wear by periodic testing

and will participate in Westinghouse Owner's Group (WOG) activities to establish recommended

testing options, acceptance criteria, and recommended corrective actions. When issued, the

3 Westinghouse WCAP-12866 is a Class 2 Proprietary Westinghouse Report. In NRC BL 88-09, the

staff specifically stated, in part, that Oeach addressee is requested to establish an inspection program

to monitor thimble tube performance, that includes the establishment, with technical Justification

[emphasis added], of an appropriate thimble tube wear acceptance criterion."

The 80 percent through-wall wear acceptance criterion established in the report is not considered by

the NRC to be proprietary in content because the staff did not intend this type of information to be

withheld from the public when it issued NRC BL 88-09. Further, this type of information has been

divulged to the general public in the past in other industry correspondence, NRC correspondence, NRC

audit reports, and safety evaluations. However, the remaining specific data, equations, and information

are considered to be proprietary in content and will be withheld from the public, in accordance with the

staff's acceptance of Westinghouse Electric Company's Proprietary Affidavit on WCAP-1 2866.

Therefore, only a general basis on the acceptability of Westinghouse's 80 percent through-wall wear

acceptance criterion will be given in this SER.

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WOG recommended actions will be reviewed and the Alabama Power Company program

modified, as appropriate. In the interim period prior to issuance of the WOG recommendations,,

Alabama Power Company will continue with its current progiam which'isconsistent with the

requirements of NRC Bulletin 88-09" (emriphasis added).' '

In its January 12, 1990 audit trip report, the NRC noted that 'The Ucensee stated that eddy current

inspections will be performed during every refueling outage until there is sufficient data to iustify -

longer inspection intervals" (emphasis added)., li addition, the NRC concluded: 'The Ucensee has

considered long term corrective actions 'and is prepared to replaceltubes if necessary'.' Although

no long term'commitments have been made, Weuriderstarid that the Ucensee will continue

participating in Industry programs (such as WOG) and follow new developments related to this

issue." ' ':- - - ' '

The FNP Flux Detector Thimble Inspection Program has been maintained in accordance with the

November 2, 1988 response to NRC Bulletin 88-09, Including the potential for modifications to the

-Irispection Interval. This potential for modifications to the inspection interval was acknowledged by

the NRC in its January 12, 1990 audit trip report; ., 9 ' .; , .-.- . -

conformance with the current recommendations of WCAP-12866, Bottom Mounted lnstrument. ';

Flux Thimble Wear" dated January 11, 1991. -The Inspection schedule is not a pre-established, .

fixed frequency. The inspection schedule Is variable, based on projections of thimble tube wear -

l -calculated from measurements of current wear. 'Early in the inspection program, inspections were'

* performed every 'outage to establish we&rrate patterns characteristic of each unit. 'Once a history '

had been established, the WCAP-12866 wear rate projection methodology became the basis for!-:.

- determining the acceptable-interval between inspections. After each inspection the recommended - - -

date of the next inspection is determined. Operating experience at FNP and across the industry.

indicates that the wear rate prediction methodology, is a conservative way to project wear of the

flux thimble tubes. - _ - _

In 1993 the schedule of inspections at FNP was changed from every outage to every other outage,

unless wear predictions dictated that an Inspection be scheduled at an earlier date. This change

was based on Westinghouse's recommendation.

The FNP Unit 2 flux thimble tubes are currently inspected every other outage in accordance with -;

'WCAP-12866 guidance. The last inspection was performed during the Fall 2002 refueling outage

(2R15). The next inspection is scheduled for the Fall 2005 refueling outage (2R17). Planning

activities are in progress to replace the Unit 2 flux thimble tubes. After the flux thimble tubes are

replaced the inspection schedule will be revised In accordance with the latest guidarice based on"

WCAP-12866,'and Industry and FNP operating experience; '

: The FNP Unit 1 flux thimble tubes were replaced with wear resistant, chrome plated thimble tubes

during the Fall 1998 refueling outage (1 RI5). In 2003 the inspection schedule was extended to -

every third refueling outage based on Westinghouse's'recommendation: The last inspection was

performed during the Fall 2001 refueling outage (1 R17). The next inspection is scheduled for the

Spring 2006 refueling outage (1 R20).

... -.

The current inspection schedules for FNP Units' 1 and 2 are established based on predictions of

flux thimble tube wear.-.These predictions are calculated in accordance with the methodology described In WCAP-12866. The 'unit-specific wear history is used as input to' the wear calculation.

Both industry and FNP specific operating experience is considered when the date for the next

inspection Is established. This experience confirms that the WCAP-12866 methodology Is a

conservative way t6 manage wear of flux thimble tubes. ' -

The applicant's supplemental response to'RA1 B.5.2-3, by letter dated June 25, 2004 (SNC

Letter No. NL-04-1096),-provides the following cla'rifications:' ; ' '

The response co'nfirms that the applicant is using the methodology in WCAP-1 2866 as

the Current basis for implementing its Flux Detector Thimble Inspection Program.

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a

* The'applicant'is currently inspecting the FNP Unit 2 thimble tubes once every other RFO

(i.e., once every 36 months), with the last inspection having been performed during RFO

15 in 2002.

* The applicant replaced the thimble tubes at FNP, Unit 1, during the 1998 RFO (RFO

1 Ri5) with thimble tubes fabricated with chror'nium plating; the applicant inspected the

new thimble tubes at FNP, Unit 1, for the first time in 2001 during RFO 1 R17.

* The applicant will perform the second inspection of the new thimble tubes at FNP, Unit

1, in 2006 during RFO 1 R20.

In WCAP-1 2866, Westinghouse compiled plant-specific wear rate data from Westinghousedesigned thimble tubes on behalf of participating members in the WOG. Westinghouse used

its generic compilation of thimble tube wear data to derive a generic wear rate equation for

Westinghouse-designed thimble tubes. The WOG, to date, has not requested that this topical

report be formally reviewed by the staff nor has the staff endorsed this report for use. In NRC

BL 88-09, the staff stressed that monitoring programs for Westinghouse-designed thimble

tubes would be based on actual plant-specific wear data. Thus, application of the methodology

and generic wear data in WCAP-1 2866 may not be conservative if a facility's plant-specific data

project wear at a faster rate than would be projected by the report's generic data. In its review

of the applicant's response to RAl B.5.2-3, the staff noted that the response did not clarify

whether the FNP Unit 2-specific wear data were being used to support the inspection frequency

for FNP Unit 2 thimble tubes. The staff also noted that new thimble tubes at FNP, Unit 1, are

currently scheduled for inspection once every three RFOs and had only been inspected once in

1998.

During a conference call held June 7, 2004, the staff requested additional information on the

wear rate data that the applicant used to predict future wear in the FNP Unit 2 thimbles tubes

over an 18-month operating period. The staff also requested information on the applicant's

basis for establishing an inspection frequency for the FNP Unit 1 thimble tubes subsequent to

the second ECT in 2006. The applicant addressed these questions by supplementing its

response to RAI B.5.2-3 with additional information in its letter dated July 16, 2004 (SNC Letter

No. NL-04-1296). In its letter dated June 25, 2004 (SNC Letter No. NL-04-1096), the applicant

provided the following supplemental information:

For the Unit 2 thimble tubes:

* The worst case cumulative wear (for thimble tubes which have not been repositioned or

capped) from the most recent Unit 2 inspection (U2R15) data (adjusted for uncertainty)

was 58.8% for thimble tube J03 at 985.94* from the seal table. A 5% allowance for

instrument error was applied to the measured wear data.

* Nominal wall thickness of the Unit 2 thimble tubes is 0.049 +/- 0.002 inches.

* For FNP, the methodology provided in Proprietary Class 2 WCAP-12866 is used to

project thimble tube wear at the end of future operating cycles. Unit-specific measured,

wear data is adjusted for uncertainty and is input to the WCAP-1 2866 methodology to

establish the curve coefficient (i.e., exponent 'n") and determine the curve-fit representing

thimble tube wear over time. The next inspection is scheduled for an outage before any

thimble tubes are projected to exceed the acceptance criteria for wall loss, with

consideration of plant and industry experience with thimble tube wear. This process is

3-60
repeated after each inspection,' therefore the' inspection interval is re-evaluated after each

i- nspection.' ':;Y:.:o'-:-: --

The.... coefficient.... used in the latest projection of flux thimble tube wear was 0.302..;. For the

worst case cumulative wear (for thimble tubes which have not been repositioned or capped) fromthe U2R15 inspection, this equate's to wear rojections of 60.10% at the end of cycle 16, and

61.33% at the end of cycle 17. - - :'

LRA Appendix B, Section B.5.2.12, indicated that no Unit 2 flux thimble tubes would require

repositioning or capping based on the latest data, and the initial response to RAI B.5.2-3 noted

that the next Unit 2 eddy current inspection was scheduled for U2R1 7 (Fall '05). During U2R16

--'(Spring '04), five thimble'tubes were re-positioned and one was capped. SNC is currently

-considering the option of eliminating the eddy current Inspection scheduled for U2R1 7 based on

the additional margin provided by the' repositioning and capping. This would allow Unit 2 to

operate until U2R18 without further eddy current inspection. The Unit 2 thimble tubes will be

Inspected or replaced at U2R18.' The decision to eliminate the U2R17 eddy current Inspection will

' include evaluation of thimble tube wear projections performed in accordance with the WCAP12866 methodology. ,

By dated June 25, 2004 (SNC Letter No. NL-04-1096), the applicant projected, in part, that the

worst case amount of wear in the FNP-Unitf'thilmblI tubes wbiUld be"63.31percent of the

nominal wall thickness through RFO 18. .

The applicant's supplemental response to RAI B.5.2-3 clarifies that the nominal wall thickness

for the FNP Unit 2 thimble tubes is 0.049 iriched and thfat the Worst case amount of wear in

these thimble tubes was approximately 59pIerce'nt of the nominal wall thickness, including a 5

percent allowance in the wearvalue-to account forinstriument uncertainties in the ECT

measurements. The response also clarifies that the'applicant is using plant-specific FNP Unit 2

thimble tube data taken from past ECT examiriatioris, and riot the generic data, as the basis for

projecting the wear in FNP Unit 2 thimble tube's through the'c6mpletion of operating cycles 16

and 17, and potentially through the completion'of operating cycle 18. The applicant has

currently scheduled the next inspection of tiei FNP Unit 2 thimble tubes for.RFO 17, but is

considering deferring the inspections until RFO-AiB (wNhich will be scheduled for Spring 2007).-,

The results from ECT examinations pe'formedndurinj'RFO 15 project that the worst case wear

in the FNP Unit 2 thimble tubes will be 63.3 percenit of'the wall thickness through RFO 18. This

is less than the acceptance criterion used by the applicant for evaluating wear thimble tubes

(i.e.,-80 percent of the thimble tube wall thickness; refer to the evaluation of the Acceptance Criteria program attribute for'this AMP) and supports an inspection frequency of onrce every 3'

cycles based on the plant-specific wear result data from FNP, Unit 2, RFO 15. 'The applicant's

responses in its letters dated April 16, 2004 (SNC Letter No. NL-04-0617) and June 25,2004

(SNC Letter No. NL-04-1096) also demonstrate that the applicant is taking acceptable

corrective actions for thimble tubes that are projected to wear beyond the acceptance criterion

before the next inspection. Because the applicant is applying the FNP, Unit 2, specific data to

project the amount of wear occurring in the FNP, Unit 2 thimble tubes through RFO 18, and

because the applicant is taking acceptable corrective action-for thimbles tubes that cannot be

used for further service, the staff concludes that inspecting the FNP Unit 2 thimble tubes once

every 3 RFOs is acceptable...

The applicant's response dated April 16, 2004 (SNC Letter No. NL-04-0617) indicated that the

applicant had replaced the FNP Unit 1 thimble tubes in 1998 and has only inspected them once.

The applicant has scheduled the second'examination of the FNP Unit 1'thimble tubes for the

facility's 2006 RFO, which is within'2 years-of the issuance of the renewed operating license for

3-61
II

the facility. In a letter dated June 25, 2004 (SNC Letter No. NL-04-1096), the applicant

committed to submitting the same type of inspection result information for the new FNP Unit 1

thimble tubes that it submitted to support the inspections of the FNP Unit 2 thimble tubes during

either RFO 17 or 18 (i.e., inspect on a frequency of either once every other RFO, if inspecting

during RFO 17, or once every third RFO if inspecting during RFO 18). This commitment will

enable the staff to confirm that the inspection frequency for the new FNP Unit 1 thimble tubes is

consistent with the basis used to establish the inspection frequency for the FNP Unit 2 thimble

tubes and is therefore acceptable.

Based on this technical evaluation, the staff concludes that the applicant is applying plantspecific ECT examination data' as the basis for projecting the'amount of wear in the thimble

tubes through the next scheduled examinations, as well as for establishin g the inspection

frequencies for the thimble tubes at FNP, Units 1 and 2. Because this is consistent with the

staff's recommendations in NRC BL 88-09, the staff concludes that the applicant's Monitoring

and Trending program attribute for the Flux Detector Thimble Inspection Program is acceptable.

[Acceptance Criteria] In Section 5.2.8 of Appendix B to the LRA, the applicant stated that it will

evaluate the results of the thimble tube inspections using a wear rate formula to determine the

earliest projected date that a thimble tube can be anticipated to exceed the wall thickness limit.

In its BL 88-09 audit report issued on January 12,1990, the staff stated that the inspection

program applied acceptable 'state-of-the-art inspection methods with technically justifiable wear

acceptance criteria. In the BL 88-09 audit report, the'staff determined that the applicant'based

its evaluations of wear. on an acceptance criterion of 65 percernt through-wall wear in the

thimble tubes. However, during the staff's LRA audit of November 3-7,' 2003, the staff'

determined that the applicant is presently using WCAP-1 2866 as its basis for the Flux Detector

Thimble Inspection Program. This WCAP includes a through-wall acceptance criteria of 80

percent. The staff requested that the applicant provide a technical basislfor changing the

acceptance criterion for the Flux Detector Thimble Inspection Program from' 65 percent

through-wall wear and for, concluding that an acceptance criterion of 80 percent through-wall

wear will maintain the component intended functions of the thimble tubes. The staff identified

this request as RAI B.5.2-4.

The applicant provided the following response to RAI B.5.2-4 in its letter dated April 16, 2004

(SNC Letter No. NL-04-0617):

FNP is committed to monitor thimble tube wear by periodic testing and to participate in

Westinghouse Owner's Group (WOG) activities to establish recommended testing options,

acceptance criteria, and recommended corrective actions. The 65% through-wall acceptance criterion was the preliminary acceptance criterion established based on Westinghouse analysis

and acknowledged by the NRC in its January,12, 1990, audit trip report. The NRC acknowledged that 'The Licensee is participating in the Westinghouse Owner's Group (WOG) Program on

thimble tube wear. This program will develop more accurate wear scar standards and refine the

acceptance criteria for wear based on testing of tube samples from operating plants."

In January 1991, Westinghouse issued WCAP-1 2866, "Bottom Mounted Instrumentation Flux

Thimble Wear." This WCAP established a refined acceptance criterion of 80% through-wall wear.

The refined acceptance criterion included results from testing of tube samples. WCAP-12866

concludes that flux thimbles have a high residual strength even when subject to wall loss on the

order of 90%, and that the thimbles will maintain their functional and structural integrity with up to

85% wall loss for all operating modes. The WCAP recommends an acceptance criterion of 80%

through-wall wear be used for conservatism. Uncertainties inherent in the eddy current

3-62
*examination process were considered in the development of the acceptance criteria.

The Staff question also requests an assessment of whether the acceptance criterion Includes an

allowance to take into account wear that Is projected to occur in the interval between

examinations. Since the 80% acceptance criterionis aplied to the-wear which is projected toexist at the next Inspection,- wear In the Interval between inspections is accounted for. Appropriate

corrective action will be taken for flux thimble tubes which are projected to exceed the acceptance

criteria before the next inspection.

In NRC BL 88-09, the staff requested each' licensee "to establish an inspection, program to

monitor thimble tube performance, that includes the establishment, with technical justification,

of an appropriate thimble tube wear acceptance criterion (for example, percent through-wall'

loss)."

The staff reviewed WCAP-12866 and determined that the acceptance criterion in theto~pical

report was based on conservative burst tests bn Westinghouse thimble tube designs that'

support an 80 percent through-wall accejtance criterion for the thimble tubes at FNP, Units 1

and 2. This value includes an additional safety margin established by.Westinghouse for

allowable wear in the thimble tube. This safety margin, however, does not include an allowance

for instrument uncertainties, which, as a percentage of the wall thickness, must be accounted

for by either adding it tdthe ECT wear result data or subtracting it from the acceptance

criterion.

As indicated in its supplemental responseto RAI B.5.2-3, the applicant-accounts for~the

instrument uncertainties in its wear assessments for the thimble tubes by adding the instrument

uncertainties to wall measurement data after the ECT examinations have been performed.

Therefore, the applicant opts to add the instrument uncertainty (which the applicant sets at 5

percent of the FNP thimble tube-wall thickness) into the wear result data after ECT

examinations are performed. This is acceptable. The staff concludes that the applicant's 80

percent through-wall acceptance criterion is'acceptable because it is based on conservative

burst tests for the thimble tubes and it includes an acceptable safety margin for allowable wear.

Therefore, the staff concludes that the Acceptance Criteria program attribute for the Flux

Detector Thimble Inspection Program is acceptable and RAI B.5.2-4 is closed.

[Operating Experience] In Section 5.2.12 of Appendix B to the LRA, the applicant stated that

there is industry-specific and plant-specific history related to loss of material from thimble tubes

in Westinghouse reactors. The applicant also stated that the presence of wear has been

detected in multiple thimble tubes at FNP and that SNC replaced the FNP Unit 1 thimble tubes

during RFO 15 with chrome-coated; strain-hardened stainless steel thimbles. For. FNP, Unit 2,

the applicant indicated that the most recent flux thimble eddy current evaluation indicates that

no repositioning or capping will be required. -: - - -

NRC BL 88-09 documents industry experience with wear in thimble tubes of Westinghousedesigned light-water reactors. The Flux Detector Thimble Inspection Program is based on the

applicant's response to NRC BL 88-09, dated November 2, 1988. The original FNP thimble

tubes were fabricated from SA213, Type 316 austenitic stainless steel that was cold drawn and

heat treated. - . - . .

The staff's BL 88-09 audit report of January 12, 1990, provides early documentation of FNPspecific wear degradation in the thimble tubes. In the BL 88-09 audit report, the staff

I 3-63
I

documented the results of ECT inspections performed on the thimble tubes at FNP, Unit 1,

during RFOs 7, 8, and 9, and at FNP Unit 2 during RFOs 5 and 6. In the BL 88-09 audit report,

the staff also reported that the wear detected in some of the thimble tubes' at FNP, Unit 1

(ranging from 17 percent to 67 percent through-wall degradation), was more significant than the

wear reported in some thimble tubes at FNP, Unit 2 (ranging from 13 percent to 53 percent

through-wall degradation), which warranted corrective action by the applicant, based on an

original acceptance criterion of 65 percent through-wall degradation. This operating experience

indicates that the applicant's implementation of the Flux Detector Thimble Inspection Program

is achieving its intended purpose of protecting the intended functions of the thimble tubes. The

applicant also indicated that the original thimble tubes at FNP, Unit 1, were replaced during

RFO 15 with thimble tubes fabricated from chrome-coated, strain-hardened stainless steel.

The staff requested clarification as to whether the applicant used wear experience and change

in the material of fabricationlfor'the thimble tubes at FNP, Unit 1, as a basis for revising both

the scope of the prograrri, as related to frequency and number of thimble tubes inspected, and

the acceptance criterion for evaluating the results of inspections performed on the thimble tubes

at FNP, Unit 1. The staff identified this request as RAI B.5.2-5.

The applicant provided the following response to RAI B.5.2-5 in its letter dated April 16, 2004

(SNC Letter No. NL-04-0617):

The Program Scope (B.5.2.3), Monitoring and Trending (B.5.2.7). and Acceptance Criteria

(B.5.2.8) have not been revised due to the wear experience or the change in the material of

fabrication for the thimble tubes at Farley, Unit 1. All flux thimble tubes on both Units are in the

scope of the program. Wall thickness measurements will be conducted to detect loss of material

from the thimble tubes at both Units. Examination results will be'trended and wear rates will be

calculated In accordance with WCAP-1 2866 for both Units. Examination frequency will be based

on wear predictions.i Results of the wall thickness measurements will be evaluated using a wear

rate formula which is described in WCAP-12866. The wear rate formula will be used to determine

the earliest projected date that a flux detector thimble tube can be anticipated to exceed the wall

thickness limit. This determination is performed in accordance with WCAP-12866 for both units.

The program attributes of the Flux Detector Thimble Inspection Program are therefore the same for

both Units.

The applicant's response to RAI B.5.2-5 indicates that, following the 2006 ECT examinations,

the applicant will use the inspections of the new FNP Unit 1 thimble tubes and apply the

methods of WCAP-1 2866 as the basis for establishing the inspection frequency for these

components. In its supplemental response to RAI B.5.2-3, the applicant committed to provide

the wear results and wear rate projection data to the staff following the second inspection of the

new FNP Unit 1 thimble tubes in 2006, as well as their inspection frequency. The applicant's

response to RAI B.5.2-5 is consistent with this commitment and the applicant's commitment

responses to BL 88-09, and is therefore acceptable. On the basis of this determination, the

staff concludes that the Operating Experience program attribute is acceptable and RAI B.2.5-5

is resolved.

FSAR Supplement

In Section A.2.14 of Appendix A to the LRA, the applicant provided the following FSAR

Supplement for the Flux Detector Thimble Inspection Program:

The new Flux Detector Thimble Inspection Program will be implemented prior to entering the

3-64
period of extended operation to formalize examinations already being performed. The program will

be administratively controlled by plant procedures. It will be used to identify loss of material during

..the extended period of op6

eration. - " ~ .

The FSAR Supplement summary description'indicat s that the Flux" Detector Thimble

Inspection' Program will be implemented duririg' the iperiod of extended operation. The applicant

is currently implementing this program asa BL 88-09 program that was established in response

to commitments made by the applicant in response to NRC BL 88-09., In NRC BL 88-09, the':

staff anticipated that licensees ownihgbWestinghouse-designed PWRs would use' olant-specific

data from thimble tube ECT examinations to devlop the inspection frequencies for their -*

thimble tubes, and that the time between examinations could be increased if warranted by the

results of the thimble tube examinations.

In its response to'BL 88-09, the applicant cornmitted to implementing a qualified inspection

pr6gram for the FNP thimble tubes that' would be 'djusted accordingly based'on the wear'-

results of volumetric examinations performed on the thimble tubes.' The' appliant i's

appropriately using its plant-specific wear to establish -ate'sults the inspection frequencies for

the thimble tubes at FNP, Units 1gand 2'The applicant will use any wear results from additional

ECT examinations performed before the period of extended operation to adjust the wear rate

projections and inspection frequencies for the thimble tubes. This is consistent with the staff's

recommendations in NRCBL 88109 and vwith thei'applicant's commitmentsg'made in response to

NRC BL 88-09, which will carry over into the period of extended -operation for FNP,' Units land

2. The applicant's FSAR Supplement su mn"marVydescription for the Fkix'Detector'Thimble

Inspection Prograrm is a general description of this 'rocess. Because the'process described in

the FSAR Supplement for this AMP is consistenit with the recommendations 'of NRC BL 88-09,

the staff concludes that the FSAR Supplement for the Flux Detector Thimble Inspection

Program is acceptable. '

Conclusion

On the basis of its review of the applicant's program, the staff concludes that the applicant has

demonstrated that the effects of aging will'be adequatel y managed so that the int6nded -

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 rvieved the FSAR Supplement for this AMPand concludes that it provides an adequate surnmaiy description of the program, as required by

10 CFR 54.21(d). '-' '' " < ' '' ' *-. 

3.0.3.3.2 External Surfaces Monitorinfg Program -- - : -

Summary of Technical Information in the ;r lication i' '- -- -

In Section B.5.3 of Appendix' B to the LRA,th'e- appli'cant stated tha't the External Surfaces ;

Monitoring Program is 'new plant-specific 6onhditi6nh Ionitoring-prog'ram'tha 't -will implement

at FNP, Units 1 sand 2 priorto tohe period of 'extended operation. This 'new program will identify

loss of material caused by corrosion or wear of 6ektenmals'Lrfaces 'of carbon 'steel,' low-alloy

steel,' and other susceptible riaterials in corhporients that require aging management for license

renewal.

Staff Evaluation - - " '

-3-65
I - - _ _ it

[Program Scope] In Section B.5.3.4 of Appendix B to the LRA, the applicant stated that the

new program will manage accessible and insulated susceptible external surfaces of

components that are within the scope of license renewal. Such susceptible external surfaces

include carbon steel and low-alloy steel surfaces located. within both inside and outside

environments, and galvanized steel, cast iron, copper all6ys, and aluminum surfaces located in

outside environments. The new External Surfaces Monitoring Program will also manage the

loss of material, cracking, and the change of material properties in elastomers. The staff

determined that the program scope includes the components for which the program manages

aging. On the basis of this determination, the staff concludes that the program scope is

acceptable.

[Preventive Actions] In Section B.5.3.5 of Appendix B to the LRA, the applicant stated that,

while monitoring activities will include actions to monitor and report conditions, no preventive

actions are associated with this monitoring program. The staff determined that the External

Surfaces Monitoring Program is an inspection-based condition monitoring program and that, as

such, the program does not require preventive or mitigative action to preclude the occurrence of

an aging effect. On the basis of this determination, the staff concludes that the preventive

actions are acceptable.

-[Parameters Inspected or Monitored] In Section B.5.3.6 of Appendix B to the LRA, the

applicant stated that it will observe the surface conditions of selected components to detect the

loss of material due to corrosion or wear; accessible portions of- piping or tubing to detect the

loss of material due to fretting, flange leakage, missing or damaged insulation, or damaged

coatings; and accessible in-scope elastomers to detect age-related degradation.

The staff determined that the parameters inspected are linked to the degradation of the

component intended function and should detect the presence and extent of the aging effects.

On the basis of this determination, the staff concludes that the parameters inspected or

monitored are acceptable.

[Detection of Aging Effects] In Section B.5.3.7 of Appendix B to the LRA, the applicant stated

that it will perform visual inspections to examine all accessible portions of the systems. The

staff recognized that visual examination is an appropriate method to detect corrosion, but

cannot be used in isolation to quantify corrosion.. In RAI 3.4-7, the staff requested the applicant

to explain how it will manage loss of material on the exterior bott6m surface-of the CST which is

not accessible for visual inspection. In its response dated March 5, 2004, the applicant stated

that it will revise the One-Time Inspection Program to include a thickness measurement of the

bottom of the Unit 1 CST before the period of extended operation. The exterior bottom

surfaces of the auxiliary steam condensate tanks and condensate return unit tanks are

accessible for visual inspection. Based on the applicant's response, the staff finds the one-time

inspection of the CST bottom acceptable to manage this aging effect. When visual examination

detects corrosion; it would then use supplemental examination methods (i.e., surface or

volumetric) to quantify the degree of corrosion. The staff determined that the use of visual.

inspection to observe surface condition is an acceptable means to detect corrosion and agerelated degradation. On the basis of this determination, the staff concludes that the detection

of aging effects is acceptable.

[Monitoring and Trending] In Section B.5.3.8 of Appendix B to the LRA, the applicant stated

that it will establish baseline documentation of the condition of the managed surfaces before the

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beginning of the period of extended operation. The applicant will use existing information on

these surfaces to establish baseline documentation, or if no histori6al data are available, the

applicant will perform a'baseline inspection"Theapplicant will monitor and trend degradation of

external 'surfaces in' accordance'with established pro6edures and guidelines. .Inspectionfrequency will be subj66t to inddifidation based on'plant-specific environments and observed

degradation. -The applicant will either increase or decrease Inspection frequency for a specific

system,cormponent, or area, as necessary, to preclude component failures. :The staff -

determined that this monitoring and trending element describes date collection and trending to'

provide predictability of degradation. On the basis of this determination, the staff concludes

that monitoring and trending element is acceptable' -

[Acceptance Criteria] In Section B.5.3.9 of Appendix B to the LRA, the applicant'stated that

acceptance criteria will be contained in the applicable inspection procedures, and that these

criteria will be directlyc'orrelated to the indications of aging effects. By RAI B.5.3-1, staff

requested the applicant to discuss the criterialto determine acceptability during these,. -

inspections. In its response dated March 5,'2004,' the applicant stated that acceptance criteria

are to be commensurate with industry code, standards and guidelines, and are to also consider

industry and 'plant-spd6ific operating experience. !Where practical, acceptance criteria will be

specifically tailored to the component type, materials of construction, and expected aging

effects. Inspectioh criterial may include'flaking'-or peeling of paint, rust, scale,'rust stains,

cracking or visible leakage.' Acceptance criteria will ensure an inspected component does not

exhibit any visible indications'that could result in a failure of component to perform its intended

function prior tothe next inspection, and will identify if corrective action is needed.'The

evaluation criteria will consider notfonly the current severity of the degradation, but the expected

environmental aggressiveness of the arei'sbrrounding the component. - :

The staff determined that the acceptance criteria of industry code, standards, and guidelines

described by the applicant provide adequate criteria against which to evaluate the need for

corrective actions. On the basis of this determination', the staff concludes that the acceptance

criteria are acceptable.'

[Operating Experience]' In Section' B.5.3.1 3 of Appendix B to the LRA, the applicant stated that

there is no 'programmatic operating experiencefor this program. There are non-nuclear

industry and other related histories related to'th6'loss of material of external surfaces and of

age-related degradation of eldstoreier hoies,'[6it the'lack of this operating experience should

not preclude implementation of this program.(The-use of conservative acceptance criteria and

liberal corrective actions will accomplish an effective AMP.

The staff determined that the applicant's review of operating experience was adequate, and

that it is a' a'ddition to or duplicates that of othier'programs that the staff has reviewed and,

approved. On the basis of this determination, the staff concludes that operating experience is

acceptable. ' ' ' ' ,' 

FSAR Supblement '- '* -i -' 's ;;' - - ,n -

In Sectiori A.2.15 of Appendix A to the LRA,the applicant provided its FSAR Supplement for.

the External Surfaces Monitoring Program..'The staff reviewed the FSAR Supplement and - -

found that the summary description contains'a sufficient level of information to satisfy 10 CFR

54.21 (d) and is acceptable. '; -'

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I 1.

Conclusion

On the basis of its review of the applicant's program, 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 FSAR Supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by 10

CFR 54.21 (d).

3.0.3.3.3 NiCrFe Component Assessment Program

Summary of Technical Information in the ApDplication

Section B.5.8 of Appendix B to the LRA discusses the NiCrFe Component Assessment

Program. The applicant stated that the NiCrFe Component Assessment Program will be

developed to address industry concerns regarding the potential for PWSCC in nickel alloy

components exposed to the reactor coolant environment. The new program will assess the

susceptibility of nickel-based alloy components to PWSCC and provide for any required

augmented inspection requirements to ensure that the component functions will be maintained

during the period of extended operation. The applicant stated that, based on the results of

nickel alloy component assessments, the inspections normally accomplished under the FNP

Inservice Inspection and Borated Water Leakage Assessment and Evaluation Programs may

be enhanced with additional inspection activities. The applicant stated that it supports

development of improved industry data, models, and inspection methodologies through active

participation in the EPRI MRP Alloy 600 Issue Task Group (ITG) and the WOG.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the NiCrFe Component Assessment

Program to determine if the program demonstrated, through objective evidence, that the effects

of aging from various age-related degradation mechanisms will be adequately managed so that

the intended function of the-components comprised of nickel-based alloys will be maintained

consistent with the CLB for the period of extended operation. Because the applicant has yet to

develop the NiCrFe Component Assessment Program, the staff used Aging Management

Review-Generic, Branch Technical Position (BTP) RLSB-1, under the SRP-LR, as the

guidance to evaluate the elements of the program.

GL 97-01, "Degradation of Control Rod Drive Mechanism Nozzle and Other Vessel Head

Penetrations," dated April 1, 1997, provides the staff's original basis for inspecting Alloy 600

reactor vessel head penetration nozzles in U.S. PWRs. Between November 2000 and April

2001, RCPB leakage was identified from the reactor vessel head penetration nozzles of four

U.S. PWR light-water reactor facilities. Supplemental examinations of the degraded nozzles

indicated the presence of circumferential cracks in four of the control rod drive mechanism

(CRDM) nozzles. These cracks initiated from the outer surface of the nozzle, either in the -

associated J-groove weld or heat-affected zone, and not from the inside surface of the nozzle,

as the industry responses to NRC GL 97-01 assumed. These cracks penetrated through the

nozzles and were the first identified instances of circumferential cracking in U.S. reactor vessel

head penetration nozzles. In NRC BL 2001-01, "Circumferential Cracking of Reactor Pressure

Vessel Head Penetration Nozzles," dated August 3, 2001, the staff discussed the generic safety

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significance and impact of these cracks on reactor vessel head penetration nozzles and

recommended that enhanced visual examination or volumetric examination methods be used

for the inspection of these components.

In March 2002, during a refueling outage at the Davis-Besse Nuclear Power Station, the

licensee reported the occurrence of reactor coolant leakage from a reactor-vessel head

penetration that resulted in significant boric acid-related wastage of the reactor vessel head.

The wastage affected the entire thickness of a localized area of the reactor vessel head around

a penetration nozzle, with the exception of ts cladding. On March 18, 2002, the NRC issued

NRC BL 2002-01 W to owners of PWR designs, requesting that the licensees address the impact

of the Davis-Besse event on the structural integrity of their reactor vessel heads and associated

penetration nozzles. On August 9,2002, the staff issued NRC BL 2002-02, "Reactor Pressure

Vessel Head and Vessel Head Penetration Nozzle Inspection Programs," to address additional

technical issues resulting from the Davis-Besse event. In NRC BL 2002-02, the staff

specifically suggested that further augmented inspections, mrore comprehensive than those

suggested in NRC BL 2001-01, be performed on reactor vessel head 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 licensees the frequency and extent of examination of nickel-based alloys

and welds in the reactor pressure vessel (RPV) heads due to PWSCC., On August 21,'2003,

the staff issued NRC BL 2003-02, "Leakage from Reactor Pressure Vessel Lower Head

Penetrations and Reactor Coolant Pressure Boundary lntegrity,".to advise licensees that RPV

lower head inspections may need to be supplemented with additional measures to assure

RCPB leakage is detected. On February 23, 2004, the staff issued First Revised Order EA-03-

009, to modify the inspection requirements for reactor pressure vessel heads at PWRs.

During V.C. Summer refueling outage 12 (October 2000), a through-wall crack was identified in

the RV hot-leg nozzle safe-end weld. This weld was fabricated from Alloy 82/182 weld material.

NRC INs 2000-17 and 2000-17, Supplement.1,'dated October 18, 2000, and November 16,

2000, respectively, provide details of the V.C. Summer RV hot-leg nozzle weld-cracking event.

Because the V.C. Summer main coolant loop weld-cracking event involves Alloy 82/182 weld

material, the staff has been addressing the effect of ,PWSCC on Alloy 82/182 piping welds on a

generic basis for all currently operating PWR plants. To resolve this current operating issue,

the industry is taking the initiative to (1) develop overall inspection and evaluation guidance, (2)

assess the current inspection technology, and (3) assess the current repair arid mitigation

technology. An interim industry report, "PWR Materials Reliability Project Interim Alloy 600

Safety Assessment for US'PWR Plants (MRP-44), Part 1: Alloy 82/182 Pipe Butt Welds," was

published in April 2001 to justify the continued .operation of PWR plants while the industry

completes the development of the final.report.,-The staff documented its'acceptance of this _finai'dusrycceptanceiss fthis interim report in an SE issued June 14;2001 .- The final industry report on this issue has not yet

been published.. Pending its .receipt of the final report and additional ultrasonic testing (UT)

inspection data from piping involving Alloy 82/182 weld material from the industry, the staff ispursuing resolution of this current operating issue pursuant to 10 CFR Part 50.

Under Appendix A2.18 to the LRA, the applicant stated that it will implement the new NiCrFe

Component Assessment Program before the period of extended operation.. In its commitment,

the applicant stated that the NiCrFe Component Assessment Program will be developed to

address industry concerns regarding the potential for PWSCC in nickel alloy components

exposed to the reactor coolant environment. This new program will assess the susceptibility of

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II

nickel-based alloy components to PWSCC and provide for any required augmented inspection

requirements to ensure that the component functions will be maintained during the period of

extended operation. The FNP program scope includes nickel-based alloy RCPB components

with known or potential susceptibility to PWSCC, excluding SG tubes (which are specifically

addressed by the Steam Generator Program) and reactor internals (which are specifically

addressed by the Reactor Vessel Intemals Program). The applicant will develop the NiCrFe

Component Assessment Program to ensure that the component functions will be maintained

during the period of extended operation.

In light of the previous discussion with respect to 82/182 welds, the staff believes that the

applicant's commitment should reflect that the lessons learned from industry initiatives and

research will become part of the NiCrFe Component Assessment Program. Because the

program has not been developed, the applicant has not demonstrated that it will identify and

assist in managing the effects of age-related degradation mechanisms.

Therefore, in RAI B.5.8-1, the staff requested the following actions of the applicant:

Please modify commitment A2.1 8 to assure that interim report "PWR Materials

Reliability Project Interim Alloy 600 Safety Assessment for US PWR Plants (MRP-44),

Part 1: Alloy 82/182 Pipe Butt Welds," and its final version will be used as part of the

basis for the NCAP. The commitment should state that the NCAP will be submitted with

sufficient time for staff review and approval to determine if the program demonstrates

the ability to manage the effects of aging per 10 CFR 50.54.21 (a)(3).

In its response to RAI B.5.8-1, dated June 10, 2004 (SNC Letter No. NL-04-0967), the applicant

stated that it will revise Appendix A.2.18, 'NiCrFe Component Assessment Program," to the

FNP FSAR Supplement to add that FNP will continue to participate in industry initiatives (such

as the WOG and the EPRI MRP). Susceptibility rankings and program inspection requirements

will ensure that the applicant is consistent with the later version of the EPRI MRP's safety

assessment regarding Alloy 82/182 pipe butt welds or its successors. The applicant also

committed to submit an inspection plan for the NiCrFe Component Assessrmnent Program for

NRC review and approval at least 24 months before entering the period of extended operation

for the FNP units. To obtain NRC staff's approval of its inspection plan for the NiCrFe

Component Assessment Program prior to the period of extended operation for the FNP units,

the applicant must submit a license amendment request. After the NRC staff's approval of the

inspection plan for the NiCrFe Component Assessment Program, any future changes to the

inspection plan will be evaluated in accordance with the 10 CFR 50.59 process. The staff

concludes that the implementation of the commitments made in response to RAI B.5.8-1 will

ensure that the appropriate program changes will be implemented (i.e., those that assure the

structural integrity of the'reactor vessel heads and other nickel-based alloys in the primary

coolant system during the period of extended operation). Therefore, the staff considers RAI

B.5.8-1 closed.

[Program Scope] The applicant stated that the scope of the NiCrFe Component Assessment

Program includes nickel-based alloy RCPB components with known or potential susceptibility to

PWSCC, excluding SG tubes, which are addressed by the Steam Generator Program, and

reactor internals which are addressed by the Reactor Vessel Internals Program. The action

required of these BL's is addressed in the Borated Water Leakage and Assessment Program.

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I i II
[Preventive Actions] The applicant stated that the'NiCrFe Component Assessment Program

does not contain any direct prevntive'or mitigating attributes and fliat the Water Chemistry

Control Program provides prevention attributes;- Th applicant stated that material replacement

was also an available optionto prevent or mitigate'the potential for PWSCC. The Preventive

Actions program attribute did not clearly iridicate'what actions or what replacement materials

the applicant would use to demonstrate acceptable management of age-related degradation

mechanisms. -.

[Parameters Inspected or Monitored] The applicant stated that the NiCrFe Component

Assessment Program will not directly inspectdor 'monitor cracking within NiCrFe alloy.,

components and that the program assessment will utilize the most current industry susceptibility

models to develop asset of plant-specific inspection requirements to address potential PWSCC

in FNP NiCrFe components. Because fthe'NiCrFe'Component Assessment Program is a plantspecific program that ranks cbmpor nets'ss'sceptible-to PWSCC, rather than a condition

monitoring or performance program, asddefined by BTP RLSB-1, the applicant must --

demonstrate that the ranking of the components for susceptibility to PWSCC is appropriate and

consistent with industry experience and regulatory requirements.

[Detection of Aging Effects] The applicant stated that this assessment program will not directly

detect or siz6ePWSCC cracks within the NiCrFe Component Assessment Program

components, but it will be used to 'reco' 6e6d'augmented inspection locations, schedules, and

techniques based upon the capability of detecting tight PWSCC-type cracks before any loss of

component intended function. These techniques may include visual, surface, or volumetric

methods.

The staff expects that aging effects can'be detected before there is amloss of intended function.

'This expectation is based on operating experience'to date and a'combination of engineering

evaluations to predict PWSCC, periodic visual inspection, and nondestructive testing to validate

predictions. This program element describes the "when, where, and how" aspects of program

data collection; 'The applicant'stated'that thiiee itit of this" element was to detect the effects of

aging before'loss of 'component intended fdrictioin, but did not provide the justification to support

the program's ability t6 accomplish this.'

[Monitoring and Trending] The applicant stated that it will perform the cracking susceptibility

assessment,' subsejquent identification of enhanced inspection requirements, and any initial

inspections for both Units 1 and 2 before entering the period of extended operation. The

applicant stated that it will integrate 'pro-gram inspections with the FNP. Inservice Inspection

Program inspections'and that it will track insp6ction results within the FNP ISI plan.

The staff finds that this program element does not provide adequate detail to assure that the

effects of PWSCC are managed. For instance, the element does not discuss how the applicant

will evaluate the data/rbesults'againist'the acceptance criteria and how it will make a prediction -

regarding the rate of degradatiorn. This prediction' is made to confirm'that the timing of the next

schedul6d in'spe ctio n'will oc6Ur before a loss of the system/component intended function.

[Acceptan'ce Criteria] The applicant stated that the acceptance criteria for any flaws identified

will be based upon ASME Secti6n XI requiremerit6 or other acceptable fracture mechanic :

methods. If the'flaw is to remain' in service,'the acceptance 'evaluation will consider component

stresses, updated crack growth'rate models;and material toughness. -

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I I

At a minimum, the applicant is required by 10 CFR 50.55a to comply with the flaw acceptance

criteria specified for ASME Class 1 components in the ASME Code, Section XI, Articles IWA3000 and IWB-3000, regardless of whether the material is fabricated from Alloy 600. The

applicant may use alternative acceptance criteria either from the applicant or the industry, if the

alternative criteria have been submitted to and accepted by the staff pursuant to 10 CFR

50.55a(a)(3). The acceptance criteria stated were not definitive enough to determine if the

applicant would allow pressure boundary leakage, if the fracture mechanics analysis

determined that the component could perform its intended function.

By RAI B.5.8-1, the staff requested the following actions of the applicant:

Under Appendix A2.18 of.the LRA, the applicant stated that it will implement the new

NiCrFe Component Assessment Program (NCAP) prior to the period of extended

operation. In its commitment, the applicant stated that the NiCrFe Component

Assessment Program will be developed to address industry concerns regarding the

potential for primary water stress corrosion cracking (PWSCC) in nickel alloy

components exposed to the reactor coolant environment.

The applicant's commitment needs to reflect that the lessons learned from industry

initiatives and research will become part of the NCAP. . The applicant is requested to

modify commitment A2.18 to state that the NCAP will be submitted with sufficient time

prior to the period of extended operation in order for staff review and approval to

determine if the program demonstrates the ability to manage the effects of aging in Alloy

600 components per 10 CFR 50.54.21 (a)(3). Also add a commitment that interim report

'PWR Materials Reliability Project Interim Alloy 600 Safety Assessment for US PWR

Plants (MRP-44), Part 1:,Alloy 82/182 Pipe Butt Welds," and/or its final version,,will be

used as part of the basis for the NCAP when the ranking of components' susceptibility to

PWSCC is performed.

The applicant's response dated April 29, 2004 (SNC Letter No. NL-04-0715), and its

supplemental response; dated June 10, 2004 (SNC Letter No. NL-04-0967), to RAI B.5.8-1,

stated that the FNP FSAR Supplement Appendix A.2.18, NiCrFe Component Assessment

Program, will be revised to reflect its continued participation in industry initiatives. Through its

involvement, it will update program susceptibility rankings and inspection requirements, and

that the NiCrFe Component Assessment Program will be submitted at least 24 months prior to

the period of extended operation for NRC review. During discussions with the staff, the

applicant and staff agreed that the program elements would be resolved when the NiCrFe

Component Assessment Program is finalized and submitted for staff review and approval.

Based on the applicant's responses and its commitment to submit the program for staff review

prior to the period of extended operation, the staff considers RAI B.5.8-1 closed.

[Operating Experience] The applicant indicated that currently no evidence of PWSCC exists in

its nickel-based alloys to date (in particular, Alloy 600 materials with 82/182 welds)., The:

applicant stated that it was in the process of procuring replacement RPV heads and will replace

them before entering the period of extended operation. The material used for the replacement

will utilize thermally treated Alloy 690 base metal, with Alloy 52/152 weld metal for all head -

penetrations. The staff considers the use of Alloy 690 base metal with Alloy 52/152 weld metal

for the penetrations to be a generally accepted method of material substitution resulting from

PWSCC-related cracking. This demonstrates where an existing program (element) has

3-72

li
succeeded because it used objective evidence based on operating experience to intercept the'

effectsbof anhage-related degradation mechanism in a timely manner; therefore,'it is acceptable

to the staff.

FSAR Supplement^ -

, .... w **1 . ,. . . : -,-., . -1

In its responses to RAI B.5.8-1, dated April 29, 2004 (SNC Letter No. NL-04-0715) and June

10, 2004 (SNC Letter'No.' NL-04-0967), the applicart stated that it will revise Appendix A.2.18

to the FNP FSAR Supplement. In its'lette'r dated April 29, 2004, the applicant stated the

following: - , -

FNP FSAR Supplement Appendix A.2.18, NiCrFe Component Assessment Program, will be -

revised to add the following text: - -; - - - - . *

FNP will continue to participate in Industry initiatives (such as the Westinghouse Owners Group

and the EPRI Materials Reliability Program). Susceptibility rankings and program inspection -

requirements will be consistent with the latest version of the EPRI Materials Reliability Program

safety assessment regarding Alloy 82/182 pipe butt welds or its successors.

SNC will submit an inspection plan for the NiCrFe Component Assessment Program for NRC - review and approval at least 24 months prior to entering the periods of extended operation for the

-FNP units.,: - - f * - ~ -~ ;- f- ; ~ -:-

In its supplemental response to RAI B.5.871, dated June 10,2004 (SNC Letter No. NL-04-

0967), the applicant clarified that it will revise the FNP License Renewal Future Action -

Commitment List accordingly. By letter dated July 27, 2004 (SNC Letter No. NL-04-1267), the

applicant included the above statements regarding its NiCrFe Component Assessment

Programs in its FNP-License Renewal Future Action Commitments, as stated.- ;

Based on the above, the staff found that the FSAR Supplement summary description contains a

sufficient level of information to satisfy -10 CFR 54.21(d), and is therefore acceptable.

Conclusion,.

The staff has reviewed the information provided in Section B.5.8 of Appendix B to the LRA, as

supplemented by the applicant's supplemental responses to RAI B.5.8-1 dated April 29, 2004

(SNC Letter No. NL-04-0715) and June 10,2004 (SNC.Letter No. NL-04-0967). On the basis

of this review, the applicant has demonstrated that it will have a program in place, reviewed and

approved by the staff, which demonstrates that the effects of aging' associated with NiCrFe

Class 1 components will be adequately managed so that the intended functions will be - maintained consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff reviewed the associated FSAR Supplement for this AMP and concludes

that the FSAR Supplement provides an adequate summary description of the program, as.

,required by 10 CFR 54.21(d). - - - ;

*. - -f - - }t,;~ * :- 'r................. , - - a ,;

3.0.3.3.4 Periodic Surveillance and Preventive Maintenance Activities Program

* '", . ' .J.',. , *-O', '-: -''-'.'? 

Summary of Technical Information in the ApDlication

The applicant described its Periodic Surveillance and Preventive Maintenance Activities in,

Section B.5.9 of a letter dated June 18, 2004 (SNC Letter No.- NL-04-1038). The Periodic

,3-73
I

Surveillance and Preventive Maintenance Activities is a new, non-GALL program that was not in

the original LRA. The program provides for periodic inspections and testing of the internal

elastomer diaphragms for the boric acid tanks, reactor makeup water storage tanks, and

condensate storage tanks (CST) for evidence of defects and age-related degradation, such as

changes in material properties, cracking, and loss of material. By letter dated August 31, 2004

(SNC Letter No. NL-04-1594), the applicant added periodic inspections of the charging/high

head safety injection (HHSI) pump casings for loss material (base metal corrosion due to clad

cracking) to the Periodic Surveillance and Preventive Maintenance Activities (PSPMA).

Inspection intervals are dependent on the component material and environment and take into

consideration industry and plant-specific operating experience and manufacturer

recommendations. No operating experience is specifically applicable to the Periodic

Surveillance and Preventive Maintenance Activities. This program is implemented through

repetitive tasks and surveillances. The Periodic Surveillance and Preventive Maintenance

Activities credited for license renewal will be implemented before the period of extended

operation.

Staff Evaluation

In Section B.5.9 of its letter dated June 18, 2004 (SNC Letter No. NL-04-1038), the applicant

described its Periodic Surveillance and Preventive Maintenance Activities Program to manage

aging of the elastomer diaphragms for the boric acid tanks, reactor makeup water storage

tanks, and CSTs. By letters dated August 31, 2004 (SNC Letter No. NL-04-1594) and

September 15, 2004 (SNC Letter No. NL-04-1801 and response to RAI 3.2-8), the applicant,

described its PSPMA to manage aging for the charging/HHSI pump casings. The Periodic

Surveillance and Preventive Maintenance Activities Program is not based on a GALL Report

program; therefore, the staff reviewed the program using the guidance in BTP RLSB-1 in

Appendix A to the SRP-LR. The staff's evaluation focused on managing aging effects through

incorporation of the following 10 elements from RLSB-1-program scope, preventive actions,

parameters monitored'or inspected, detection of aging effects, monitoring and trending,

acceptance criteria, corrective actions, confirmation process, administrative controls, and

operating experience. The applicant indicated that the corrective actions, confirmation process,

and administrative controls for license renewal are in accordance with the site-controlled Quality

Assurance Program. Section 3.0.4 of this SER provides a separate discussion of the staff's,

evaluation of the' applicant's Quality Assurance Program, and the evaluation of the remaining

seven elements is provided below. The staff also reviewed the FSAR Supplement to determine

whether it provides an adequate description of the program.

[Program Scope] The Periodic Surveillance and Preventive Maintenance Activities include

those preventive maintenance and surveillance testing activities credited with managing the

aging effects identified in the AMRs. The components include the internal diaphragms for the

boric acid tanks, reactor makeup water storage tanks, CST, and charging/HHSI pump casings.

The staff finds that the applicant's description of the scope adequately includes the components

which credit this program; therefore, the staff finds the scope acceptable.

[Preventive Actions] The applicant identified the Periodic Surveillance and Preventive

Maintenance Activities as a condition monitoring program. The inspection and testing activities

performed by this program do not prevent aging effects. This assessment is in accordance with

the GALL Report which states that'condition monitoring programs do not rely on preventive

action and thus, preventive actions need not be addressed in condition monitoring programs.

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I . 11
The staff agrees with'the'applicant's assessrn'irit bnd does not identify the need for preventive

actions; therefore, the staff finds this acceptable.

[Parameters Monitored or Inspected] The 60plic6int sitted in the Periodic Surveillance and

Preventive Maintenance Activities that for eachinispe6tion 'or test activity, instructions on the

parameters inspected or monitored are provided to permit early detection-of degradation before

loss of component intended function. The paraim'eters'inspected or monitored are dependent

on the components and aging effects beirig rrianaged. Inspection and testing activities monitor

various parameters,' such as surface corditionr,Aloss of material, presence of corrosion products

or fluid leakage, signs 'of cracking, wall thickiess, pressure, temperature, and flow.

Surface condition and loss of material inspecti6ns of the tank diaphragm are methods to detect

degradation; however, it is" not apparent to the staff 'how inspections for the presence of

corrosion products or fluid leakage, wall thickness, pressure, temperature, or flow will detect the

presence and extent of aging 'ffects for the initernal6elastomer tank diaphragms. In RAt ' . B.5.9-1 .a, the staff requested the applicant'to explain how it will use inspections for-the

presence of corrosion products or fluid leiakage, wall thickness, pressure; temperature, and flow

to detect the presence and extent of aging effects for the internal elastomer tank diaphragms.

By letter-dated July 16, 2004 (SNC Letter No; NL-04-1296), the applicant stated that the

parameters'listed are common paramete'rs-which' can provide information on the condition of

various types of components. The parameters inspected or monito'red are dependent on the

components and the aging effects being managed. This paragraph does not indicate which

parameters will be monitored for the tank diaphragms. For each component included in the - Periodic Surveillance'and Preventive Maintenance Activities program, an implementing activity

will be created which inspects or monitorsithie parameters which provide the most reliable

indication of age-related degradation. -Inthe caseeof the tank diaphragms,-the applicant will

perform visual inspections. These inspections will include inspection of the diaphragm flotation

devices, checking for water on top of the diaphragm (fluid leakage), and visual inspection of

diaphragm material for degradation (cra6king, 'chalking, tears, etc.) where appropriate. Based

on its review, the staff finds th Wapplicarit's 4respose'to RAI B.5.9-1 .a acceptable because it - describes the specific' types of visual inspections that the'applicant will perform to detect

degradation of the tank diaphragms.

As identified by NRC l6formation Notices (IN) 80-38 and 94-63, FNP's six charging/HHSI pump

casings are susceptible to loss of material due to 6lad cracking and subsequent corrosion in the

carbon steel base'r'etal. lnspectioni iriclud&visual examinations'of the internal surfaces of the

casing's (with the rotatinrg a semibliei re oved)'arid periodic hoir-intrusivW UT exams of

accessible areas of the pump 'casings to'detect through-clad cavities (loss of material) in the

carbon steel baserniterial. -'

The' parameters' monitored or inspected elemie nt adequately describes the methods to monitor

or inspect the components credited by this activity, therefore, the staff finds it to be acceptable.,

[Detection of Aging Effects] The applicant stated that the Periodic Surveillance and Preventive

Maintenance Activities'pirovides for periodic component inspections and testing to detect aging effects. Intervals are established such that they provide for timely detection of degradation.

Inspection intervals are dependent on the'component material and environment and take into

consideration industry and plant-specific operating experience and manufacturer

recommendations. The extent and schedule-of inspections and testing assure detection of

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I

component degradation before loss of intended functions. The applicant uses established

techniques such as visual inspections.

For the detection of aging effects, the GALL Report recommends that the program provide

justification linked to plant-specific or industry operating experience that the periodic inspection'

frequencies are adequate to detect the aging effects before a loss of intended function occurs.

The applicant stated that the Periodic Surveillance and Preventive Maintenance Activities

establish intervals to provide for timely detection of degradation of the elastomer tank

diaphragms. In RAI B.5.9-1, the staff requested the applicant to provide an inspection

frequency of the tank diaphragms that would detect the aging effects prior to loss of intended

function. By letters dated July 16, 2004, and August 5, 2004, the applicant stated that agirig

management of the Condensate Storage, Reactor Make-up Water Storage, and the Boric Acid

tank diaphragms per the Periodic Surveillance and Preventive Maintenance Activities program

will be implemented prior to the period of extended operation via an inspection of a sample set

of diaphragms. The diaphragm(s) selected for this sample will be based on the age of each

diaphragm (years in operation), the severity of the diaphragm environment, and the operating

conditions (frequency and degree of the cycling of the tank's level). The initial inspections for

the sample set will be performed prior to the period of extended operation. The periodic

inspection for the diaphragm sample set will initially be established on a ten (10) year

frequency. Scheduling will be performed in accordance with existing site'procedures. This

frequency of inspection is subject to modification based on considerations such as observed

degradation and operating experience. Staff notes that vendor has indicated that inspections of

diaphragms similar to those installed at FNP after ten years of operation' show no significant

aging of the diaphragm material. Based on its review, the staff finds the applicant's response to

RAI B.5.9-1 acceptable because they adequately describe the detection of aging effects and

inspection frequency for the tank diaphragms; therefore, staff finds the detection of aging

effects element acceptable.

In its supplemental information to the LRA, by letter dated August 31, 2004 (SNC Letter No. NL04-1594), the applicant stated that the charging/HHSI pump casing inspections are existing

periodic tasks that manage loss of material in the carbon steel base metal resulting from boric

acid corrosion at locations of clad cracking. Inspections include periodic non-intrusive exams of

accessible areas of the pump casings to detect through-clad cavities (loss of material) in the

carbon steel base material. In 1996, the rotating assembly of the 2A charging/HHSI pump was

removed for a pump maintenance activity. FNP visually discovered a brownrish-red residue at

two locations in the suction end of the casing indicative of carbon steel base metal corrosion

from through-clad cracks. VT-I, VT-3, and radiography were performed, and a corrosion

wastage assessment was performed by the NSSS vendor (Westinghouse). The ?A pump was

placed on an increased frequency of inspection, with UT of the pump casing performed every

six months during the next three plant operating cycles to quantify the rate of material loss. The

results of these inspections indicated no apparent changes from the previous inspection results.

A visual exam was also performed after the third cycle of operation (March 2001). The results

of these inspections confirmed the corrosion of the carbon steel base metal is progressing at a

very slow rate. Visual examinations have been performed on charging/HHSI pump casings 1A,

1C, 2A, and 2C, and are scheduled for 1 B and 2B in 2004 and 2005, respectively., Indications

of base metal corrosion due to cladding cracks have only been found in the 2A pump casing.

The applicant further indicated that VT-1 visual inspections will be performed any time a rotating

assembly is removed during pump maintenance. UT examination is performed over all

accessible areas of the pump casings on an 18-month frequency for the 2A pump, and on a 36-

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month frequency for pumps lA, .1 1C I2B, 'and 26.

The detection of aging effects element adeq'uately'desdcribes methods to detect degradation for

the components credited by this activity; therefore, the 'staff findsit to beacceptable.

[Monitoring and Trending] The applicant stated that the Periodic Surveillance and Preventive

Maintenance Activities provide' monitoring' and trending of age-related degradation. - nspection '

and testing intervals are established such that they''result in timely detection' of componenrt'

degradation.: Inspection and testing intervai are dependent on the component material and -

environment and take into consideration industry and plant-specific operating experience and'

manufacturer recommendations. The frequency of inspection or other activities is subject to

modification based on plant-specific environment or observed degradation.' Stich 6bservations'

may dictate that an inccreased braecreas6d task frequency would be prudent for a pa'rticular'-

'activity. '-'- -- - ---- - --

For monitoring and tr'ending, the GALL R recommends that'the Periodic Surveillance and

Preventive Maintenance Activities program provide predictability of tle'extent of degradation

and timely corrective actions.. In RA! B.5.9-lc,'the staff requested the applicant to explain how

the data'collected are evaluated against the acceptance criteria to' provide a prediction of the

rate of degradation in order to confirm that the iming of the n xt 'schedul'd'inspecti n will occur

before a loss of internded function. -By letter dated July 1 6, 2004 (SNc Letter No. NL-04-1296),

the applicant stated that the acceptance criteria for the tank diaphragm inspection activities are

focused on maintaining required integrity. The inspection data and acceptance criteria are not

used to "provide a prediction of the 'rate of degradation," but rather to identify observable

degradationr in'regards to' maintaining required integrity. The insp6cti6n parameters and criteria

are focused on detectinrg'degradation that mayc hallenge the inte'rity of the tank'diaphragnms'

and initiating appropriate corrective action. Inspection of the flotation devices'is intended to' --

confirm that the devices are operating properly and are fully attached with no evidence of

degradation that could impair the'function of the flotation devices'. Water' 6n top of the:;

'diaphragm is a potential indicator'of crackinrg, perforation, or tearin' of the'diaphraggm. Visible

cracking, chalking, teas, etc.are recognized indicators of progressive agirig in elastomer '

materials. The applicant will iniVestigate conditiojis- that do not meet the acceptance'criteria and

initiate corrective action under the existing condition reporting system. Based on' its review,-the

staff finds the applicant's response to RAI B.5.9-1 .c acceptable because it adequately describes

monitoring of the tank diaphragms; the staff does not identify the need f6'Ytren'ding 'in this AMP. ; * - - A ,. r ,- - .- ;... __

In its supplemental information to the LRA, by letter dated August 31,'2004.(SNC Letter No. NL04-.1594), the applicant stated that UT examination'of the charging/HHSI pump casing is'

currently performed on an 1 8-month freq-uencyfr the 2A pumpfand on a 36-month frequehcy

for pumps lA, 1B. 1C,'2B, and 2Cf Visual inispections will be performed anytifie a' rotating

assembly is removed during pump maintenance. Any indications or relevant'conditions'of

degradationa're evaluated, including relative changes to any'previously identified indication -s.

The frequency of inspection is subject toh rdification based on th6 observed degradation andany trend from prior inspections.^ - - - - - -

The mionitoring and trending elermeint adequately describes methods to m r'nitoring' and trending

the components credited by this activity;therefore, the staff finds it to be aceptable iy t1 -t * -'o8- er ore - th a: c - pa e. !-.-v'-

[Acceptance Criteria] 'The applicant stated that the Periodic Surveillance and Preventive

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Maintenance Activities acceptance criteria will be defined in specific inspection and testing

procedures. The acceptance criteria confirm cmponrient integrity by verifying the absence of

aging effects or by comparing applicable parameters to limits based on applicable intended

functions established by the plant's design basis. The applicant will include acceptance criteria

that directly correlate to the AERMs applicable to the activity. The acceptance criteria for signs

of degradation, such as cracking, perforation, tearing, and chalking of the diaphragms, will be

based on codes, standards, specifications, vendor recommendations, industry guidance,

engineering judgment and/or site operating experience as applicable. Degradations deemed to

be unacceptable will have a condition report initiated and resolution will be handled under the

Corrective Action Program.

In its response to RAI 3.2-8, by letter dated September 15, 2004 (SNC Letter No. NL-04-1 801),

the applicant stated that the objective of the charging/HHSI pump casing UT examination

procedure is to detect loss of material in the carbon steel (e.g. cavities in the carbon'steel) base

metal that may result from a clad crack with resultant exposure to borated water. Examination'

techniques include straight beam (0 degree) and angle beam (45 degrees)-examinations. Any

indications or relevant conditions of degradation detected are evaluated. The specific pump

drawings are reviewed, and any indications not representative of the pump casing geometrical

design are reported. Relative changes in any previously' identified indications a're also reported.

Reported conditions are then evaluated under the corrective actions program. VT-1 visual

inspections will be performed any time a rotating assembly is removed during pump

maintenance.

The staff finds that the applicant's acceptance criteria based on codes, standards,

specifications, vendor recommendations, industry guidance, engineering judgment and/or site

operating experience are adequate to confirm component integrity; therefore, the staff finds the

acceptance criteria acceptable.

[Operating Experience] The applicant stated that no operating'experi6nce. exists for the new

Periodic Surveillance. and Preventive Maintenance Activities program; however, FNP's history of

successful operation demonstrates that existing preventive maintenance and surveillance

testing activities have been effective at managing the effects of aging, including identifying and

correcting degraded conditions.

The GALL Report recommends that the operating experience provide objective evidence to

support the conclusion that the effects of aging will be managed adequately so that the'

intended function will-be maintained. In RAI B.5.9-1 .d, the staff requested the applicant to

provide plant-specific and industry operating experience for degradation of.internal elastomer

tank diaphragms to suIpport the conclusion that the diaphragms will be adequately managed by

the Periodic Surveillance and, Preventive Maintenance Activities, or commit to providing.

operating experience in the future to confirm the effectiveness of this new program. By letter

dated July 16, 2004 (SNC Letter No. NL-04-1296), the applicant stated that the boric acid tank

diaphragms are made from a polyvinyl chloride (PVC) material. The CST and the' reactor

makeup water storage tank diaphragms were originally made from rubber and were'replaced in

the 1990s with thermoplastic elastomer materials. There have been no indications of

degradation or failure of the currently installed diaphragms at FNP. The vendor has indicated

that inspections of diaphragms similar to those installed at FNP show no significant aging of the

diaphragm material after 10 years of operation. FNP and industry operating history

demonstrates age-related degradation of elastomer tank diaphragms progresses slowly in the

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nonaggressive environments internal to the tanks.u Periodic visual Inspections have proven

effective at detecting age-related degradations of elastomers before loss of function and have

previously been found acceptable by the NRC staff.V-Based on the slow progression of

age-related degradation and the effectiveness 'of periodic visual inspections, SNC concludes

that the Periodic Surveillance and Preventive MWintenance Activities program will adequately

manage aging of the tank diaphragms. Baied'on its'review of the applicant's response to RAI

B.5.9-1 .c, the staff finds that the operating experience supports'the conclusion'that the Periodic

Surveillance and Preventive Maintenance Activities Program will be effective in preventing

aging of the tank diaphragms; therefore, the staff finds it acceptable.

The staff's RAI 3.2-8, dated September 14,2004, requested the applicant to provide plantspecific and industry operating experience fo-rdegradation of the charging/HHSI pump casings

to support the conclusion that the pump casings will be adequately managed by the PSPMA.

By letter dated September 15, 2004 (SNC Letter N6.' NL-04-1801), the applicant responded by

stating that periodic non-intrusive UT examinations and internal surface visual examinations 4

with the rotating assembly removed during puimp maintenance have proven successful at FNP

in detecting and managing this aging effect with no loss of intended function. Visual

examination of the internal surface of the pump casing (with the rotating assembly removed)

has successfully identified corrosion of the base metal due to cladding cracks. In the 2A - charginWIHHSI pump, an internal surface visual examination readily detected indications of

base metal corrosion due to cladding cracks. UT examination has been shown to be a reliable

technique for monitoring wall thickness (loss of material) in components; -Non-intrusive UT

examination has successfully monitored the'FNP charging pump casings for indications of loss

of material in the base metal. For the 2A charging/HHSI pump indications,.the periodic UT.- -

examinations have confirmed that actual material loss is progressing at a very slow rate. - The

frequency of inspection assures that the was thickness will not exceed ASME code

requirementsi. There has been n6oloss of intended functions in any charging/HHSI pump as a

result of this'aging effect. The operating experience demonstrates that program activities are

adequate to detect and manage loss of material in the charging/HHSI pump casings due to clad

cracking, such that the component intended function will be maintained during the period of

extended operation. Based on its review of the applicant's response to RAI 3.2-8, the staff finds

that the operating experience supports the conclusion that the PSPMA program is effective at

preventing aging of the charging/HHSI pump casings; therefore, the staff finds it to be;

acceptable. : - . -

FSAR Supplement .% 

By letter dated June 18, 2004 (SNC Letter No.-NL-04-1038), the applicant provided its FSAR -

Supplement for the Periodic Surveillance and Preventive Maintenance Activities Program for:

Appendix A, Section A.2.20, of the LRA. The staff reviewed the FSAR Supplement and finds

that the suimmary description contains a sufficient level of information to satisfy 10 CFR - 54.21 (d) and is therefore acceptable. -.1 -

Conclusion

On the basis of its review of the applicant's 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 FSAR Supplement for this AMP and finds that it provides an adequate

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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 effects of aging associated with the SCs that credit the Periodic Surveillance and

Preventive Maintenance Activities Program 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).

3.0.3.3.5 Conclusion

On the basis of its review of the applicant's AMPs, the staff concludes that for the AMPs listed

above, 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 reviewed the associated FSAR

Supplements for these AMPs and concludes that the FSAR Supplements provide an adequate

summary description of the programs, as required by 10 CFR 54.21 (d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

Pursuant to 10 CFR 54.21 (a)(3), a license renewal applicant is required to demonstrate that the

effects of aging on structures and components subject to an Aging Management Review (AMR)

will be adequately managed so that their intended functions will be maintained consistent with

the CLB for the period of extended operation. NUREG-1 800, SRP-LR, Branch Technical

Position RLSB-1, "Aging Management Review - Generic," describes ten attributes of an

acceptable aging management program. Three of these ten attributes are associated with the

quality assurance activities of corrective action, confirmation processes, and administrative

controls. Table A.1 -1, "Elements of an Aging Management Program for License Renewal," of

Branch Technical Position 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; and,

* administrative controls should provide a formal review and approval process.

NUREG-1 800, Branch Technical Position IQMB-1, "Quality Assurance For Aging Management

Programs," noted that those aspects of the aging management program that affect quality of -

safety-related structures, systems, and components are subject to the quality assurance (QA)

requirements of 10 CFR Part 50 Appendix B. Additionally, for non safety-related-related

structures and components subject to an aging management review, the existing 10 CFR Part

50 Appendix B QA program may be used by the applicant to address the elements of corrective

actions, the confirmation process, and administrative controls. Branch Technical Position

IQMB-1 provides the following guidance with regard to the quality assurance attributes of aging

management programs:

* Safety-related structures and components are subject to 10 CFR Part 50 Appendix B

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requirements, which are adequate to address all quality-related aspects of an aging

management program-cosistent with the CLB of the facility for the period of extended

operation.

* ' -'For non safety-related-related structures and components that are subject to an AMR

for license renewal, an applicant has an option to expand the scope of its 10 CFR Part

50 Appendix B program to include these structures and components 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).

3.0.4.1 Summary of Technical Information in Application

Section 3.0, "Aging Management Review Results," of the LRA'provides an AMR summary for'

each unique structure, component, or commodity group at the FNP determined to require aging

management during the period of extended operation: This summary includes identification of

aging effects requiring management and AMPs utilized to manage these aging effects.

Appendix B, "Aging Management Programs and Activities," of the LRA demonstrates how the

identified programs manage aging effects using attributes consistent with the industry and NRC

guidance. The applicant's program's and activities that are credited with managing the effects

of aging can be divided into three types of programs: (1) existing aging management programs,

(2) enhanced aging management programs', and (3) new-aging management programs.

In Section B.1.4,2"Aging Management Program Quality Control Attributes," of the LRA, the

applicant provided the following generic description of the quality attributes common to all the

plant specific aging management programs:

[Corrective Actions] FNP applies a single corrective'actions process,-regardless of the safety

classification-of the system, structure or component. Corrective actions are initiated in

accordance with plant procedures established to implement 10 CFR 50, Appendix B. -

FNP requires documentation of actual or potential problems including, but not limited to,

unexpected plant equipment degradation, damage,-failure, or malfunction. FNP will include in.

site implementing procedures for programs credited for aging management a statement

requiring corrective action be initiated whenever appropriate criteria are not met.

[Confirmation Process] The focus of the FNP confirmation process is formal follow-up actions

that must be taken to verify'effective implementation of corrective actions. Effectiveness is

measured in terms of correcting the adverse condition and precluding repetition of significant

conditions adverse to quality.'

Plant procedures include provisions for timely evaluation of adverse conditions'and

implementation of any corrective actions required, including root cause determinations and

prevention of recurrence where appropriate (e.g., significant conditions adverse to quality).

These procedures provide for tracking, coordinating, monitoring, reviewing, verifying, validating,

and approving corrective-actions, to ensure effective corrective actions have been

implemented. The corrective actions process is also monitored for potentially adverse trends.

The existence of an adverse trend due to recurring or. repetitive adverse conditions will result in

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the initiation of corrective actions.

[Administrative Controls] FNP administrative controls require formal written procedures and

other forms of administrative controls for the activities performed under the programs credited

for managing aging during the renewal term. These FNP procedures contain or will contain

objectives, program scope, responsibilities, methods for implementation, and acceptance

criteria.

3.0.4.2 Staff Evaluation

The NRC staff reviewed the applicant's aging management programs described in Appendix A,

"Final Safety Analysis Report Supplement," and Appendix B, 'Aging Management Programs

and Activities," of the FNP license renewal application. The purpose of this review was to

assure that the aging management activities were consistent with the staff's guidance

described in NUREG-1 800, Section A.2, "Quality Assurance for Aging Management Programs

(Branch Technical Position IQMB-1)," regarding quality assurance attributes of aging

management programs. Based on the staff's evaluation, the descriptions and applicability of

the plant-specific aging management programs and their associated quality attributes provided

in Appendix A and Appendix B of the LRA are consistent with the staff's position regarding

quality assurance for aging management. However, the applicant did not sufficiently described

the use of the quality assurance program and its associated attributes (corrective action,

confirmation process, and administrative controls) in the discussions provided for aging

management programs described in Appendix A. By letter dated December 12, 2003, the staff

requested that the applicant supplement the descriptions in the Appendix A, "Final Safety

Analysis Report Supplement," to include a description of the quality assurance program

attributes, including references to pertinent implementing guidance as necessary, which are

credited for the programs described in Appendix B of the LRA. This was RAI 2.1-2.

In its January 9, 2004, response to RAI 2.1-2, the applicant stated that the FSAR Supplement

(Appendix A) will be updated to include information regarding the applicability of the FNP

Quality Assurance Program to aging management programs credited to manage the aging

effects for in-scope SSCs. Specifically, the applicant stated that the FNP Operations Quality

Assurance Program will apply the quality assurance criteria of 10 CFR 50, Appendix B to the

elements of corrective action, confirmation process, and administrative controls for the aging

management program activities and implementing documents during the period of extended

operation.

On February 5, 2004, the staff held a conference call with the applicant to get. further

clarification on the RAI response. Specifically, the staff requested the applicant update the

FSAR Supplement to clarify that in addition to imposing the 10 CFR 50, Appendix B criteria on

the three (3) quality assurance attributes for all AMPs, that the AMPs would apply to all plant

systems, structures and components within the scope of license renewal and subject to those

AMPs. The applicant agreed to make such a revision to the FSAR description and provided a

revised description by letter dated March 31, 2004. In its letter dated March 31, 2004, the

applicant stated that the quality assurance criteria of corrective actions, confirmation process,

and administrative controls will apply to all safety-related and non safety-related structures and

components that perform an intended function for license renewal. Based on this revised

description, the staff concludes that the applicant will apply the corrective action program, as

described in LRA to all plant systems, structures and components (both safety-related and

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1I
non-safety-related) within the scope of license renewal and subject to the AMPs described in

Appendix B of the LRA. Therefore, RAI 2.1-2 is closed. -

; ,, ,;, , .- ,,;;,r- , ,,*

3.0.4.3 Conclusion - - - .

On the basis of the information-provided in the LRA,-as supplemented by the applicant's.

response to the staff's request for additional information, the applicant's quality assurance. -

description for its AMPs is acceptable. Specifically, the applicant described the quality

attributes of the programs and activities for managing the effects of aging for both

safety-related and non-safety-related SSCs within.the scope of license renewal and stated that

the 10 CFR Part 50 Appendix B Quality Assurance Program provides corrective actions,

confirmation processes, and administrative controls. The staff finds that the quality assurance

attributes of the applicant's AMPs are consistent with 10 CFR 54.21 (a)(3).

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

This section of the SER documents the staff's review of the applicant's AMR results for the

reactor vessel, internals, and RCS components and component groups associated with thefollowing systems: - .- -. . -, .. - , -

* -I- reactorvessel - -.

* reactor vessel internals

* reactor coolant system and connected lines

* > - steam generators . -- ; - - - - - -

-r -eft , -, A-; ;

3.1.1 Summary of Technical Information in the Application

In LRA Section 3.1, the applicant provided AMR results for the reactor vessel, internals, and

RCS components and component groups. Tables 2.3.1.1, 2.3.1.2, 2.3.1.3, and 2.3.1.4 of the

LRA identify the passive, long-lived reactor vessel, reactor internals and reactor coolant system

components that are subject to an AMR. - - - - . -

In Table 3.1.1, "Summary of Aging Management Evaluations for Reactor Vessel, Internals, and

Reactor-Coolant System 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, and RCS components and component groups that are relied on for license renewal.

In Section 3.1.2.2 of the LRA, the applicant provided information concerning Table 3.1.1

components for which the GALL Report recommends further evaluation.

The applicant's AMRs incorporated applicable operating'experierce in the determination of

AERMs. These reviews included evaluation ~of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with -

appropriate site personel to identfyi AERMs. The applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report in 2001.

: The applicant conducts ongoing review of plant-specific and industry operating experience in

accordance with the plant Operating Experience Program.

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3.1.2 Staff Evaluation

The staff reviewed Section 3.1 of the LRA to determine if the applicant provided sufficient

information to demonstrate that the effects of aging for the reactor system components that are

within the scope of license renewal and subject to an AMR will be adequately managed so that

the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff performed an audit and review to confirm the applicant's claim that certain identified

AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report." However, the staff did determine that the applicant presented

applicable material in the LRA and identified the appropriate GALL AMPs. Section 3.0.3 of this

SER documents the staff's evaluations of the AMPs. The FNP Audit and Review Report,

summarized in Section 3.1.2.1 of this SER, documents the details of the staff's evaluation of the

audit and review for these AMRs.

The staff also performed an audit and review of those AMRs that were consistent with the GALL

Report and for which further evaluation is recommended.' During the audit and review, the staff

determined that the applicant's further evaluations were consistent with the acceptance criteria

in Section 3.1.2.2 of the SRP-LR. The FNP Audit and Review Report, summarized in Section

3.1.2.2 of this SER, documents the details of the staff's evaluation of the audit and review for

these AMRs.

The staff conducted a technical review of the remaining AMRs that were not consistent with the

GALL Report. The staff evaluated whether the applicant identified all plausible aging effects

and listed the appropriate aging effects for the material-environment combinations specified.

Section 3.1.2.3 of this SER documents the details of the staff's review and evaluation of these

AMRs that are not consistent with the GALL Report.

Finally, the staff reviewed the AMP summary descriptions in the Final Safety Analysis Report

(FSAR) Supplement to ensure that they adequately describe the programs credited with

managing or monitoring aging for the reactor system components.

Table 3.1-1 summarizes the staff's evaluation of components, aging effects/mechanisms, and

AMPs listed in Section 3.1 of the LRA that are addressed in the GALL Report.

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

Components in the GALL Report.

'Component Group. > Ag!in- Eff&et7; JA"I"PrIn GALXL ' i '-- in LRAV.;i A jStaff Evauiao- I

Reactor coolant Cumulative fatigue TLAA, evaluated 10 CFR 54.21 (c)(1 )(i) Consistent with

pressure boundary damage in accordance with analyses remain valid GALL, which

(RCPB) 10 CFR 54.21(c) recommends further

components evaluation: (See

Item Number Section 3.1.2.2.1)

3.1.1-1 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

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11
,Compi nent-GMeup'c mK7-' Z AMP in' GALL , t' AP In LRA' 7Stiff : Evialuation '

Steam Generator ' Loss'of material K Inservice - Water Chemistry ' Consistent with

shell assembly due to pitting and inspection; water Control Program GALL, which

Item Number.. crevice corrosion chemistry (Appendix B.3.2);' recommends further

3.1.1.2 : Inservice Inspection evaluation. (See -

Program' (Appendix ' Section 3.1.2.2.2)

B.3.1) ' .

Pressure vessel Loss of fracture TLAA, evaluated 10 CFR 54.21(c)(1)(i) Consistent with .

ferritic materials toughness due to in accordance with analyses remain valid GALL, which

that have a neutron neutron irradiation Appendix G to recommends further

fluence greater than embrittlement 10 CFR Part 50 evaluation. '(See

1017 n1cm (E>1 _ | and RG 1.99 . Section 3.1.2.2.3), MeV .....

tem Number N ' ';

Reactor vessel Loss of fracture Reactor vessel Reactor Vessel Consistent with.

beltlin'e shell and: toughness due to surveillance Surveillance Program GALL, which .

welds 7 neutron Irradiation' _ . (Appendix B.3.4) recommends further

Item Number '? embrittlement -' , - ' evaluation. -(See

3.1.1-5 : ' - ; - , Section 3.1.2.2.3)

Westinghouse and Loss of fracture Plant specific Reactor Vessel Consistent with -

Babcock & Wilcox toughness due to Intemals Program ' GALL, which -- -,-

baffle/former bolts neutron irradiation (Appendix B.5.1) recommends further

Item Number embrittlement and evaluation. (See

3.1.1-6 void swelling Section 3.1.2.2.3)'

Small-bore Reactor Crack Initiatiorn and Inservice' ' Inservice Inspection' Consistent with

Coolant System and growth due to stress inspection; water {Program (Appendix GALL, which

connected systems corrosion cracking - chemistry; one- B.3.1); Water ' recommends further

piping -' (SCC),iritergranular time Inspection Chemistry Control evaluation. (See

Item Number stress corrosion Program (Appendix Section 3.12.2.4)

3.1.1-7 1 cracking (IGSCC), B.3.2); One-Time'

and thermal and Inspection Program '

. mechanical loading (Appendix B.5.5) '

Vessel shell ' Crack growth due to T1AA 10 CFR 54.21 (c)(1 )(i) Consistent with

Item Number ' cyclic loading - analyses remain valid GALL, which

3.1.1-10 . recommends further

evaluation. (See

. A --- Section 3.1.2.2.5) -

Reactor internals Changes in Plant specific Reactor Vessel Consistent with

-Item Number ' dimension due to Internals Program GALL, which

3.1.1-11 void swelling (Appendix B.5.1) recommends further

. ,(evaluation. (SeeSection 3.1.2.2.6):

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- o a

+_B a- ...,,...,,, r- ._, Ail Ac-'- *4._'Rr i- 4 i.*.. .. _s.~. *, t.. * I,- . 4 ,. .;.'

CComPbonentbGr6upR ' - xAgIngEffActP nLR^-',-: 1C P GADi M, 16 Stan Eau'iitn i"

PWR core support Crack initiation and Plant specific Water Chemistry Consistent with

pads, instrument growth due to SCC Control Program GALL, which

tubes (bottom head and/or primary (Appendix B.3.2); recommends further

penetrations),, water stress NiCrFe Component evaluation. (See

pressurizer spray corrosion cracking Assessment Program Section 3.1.2.2.7)

heads, and nozzles (PWSCC) (Appendix B.5.8)

for the steam

generator

instruments and

drains

Item Number

3.1.1-12

Cast austenitic Crack initiation and Plant specific Water Chemistry Consistent with

stainless steel growth due to SCC Control Program GALL, which

(CASS) RCS piping (Appendix B.3.2) recommends further

Item Number evaluation. (See

3.1.1-13 Section 3.1.2.2.7)

Pressurizer Crack initiation and Inservice None Consistent with

instrumentation growth due to inspection; water GALL, which

penetrations and PWSCC chemistry recommends further

heater sheaths and evaluation. (See

sleeves made of Section 3.1.2.2.7)

nickel alloys

Item Number

3.1.1-14

Westinghouse and Crack initiation and Plant specific Water Chemistry Consistent with

B&W baffle/former growth due to SCC Control Program GALL, which

bolts and irradiation (Appendix B.3.2); recommends further

Item Number assisted stress Reactor Vessel evaluation. (See

3.1.1-15 corrosion cracking Intemals Program Section 3.1.2.2.8)

(IASCC) (Appendix B.5.1)

Westinghouse and Loss of preload due Plant specific Reactor Vessel Consistent with

B&W baffle/former to stress relaxation Internals program GALL, which.

bolts (Appendix B.5.1); recommends further

Item Number Inservice Inspection evaluation. (See

3.1.1-16 Program (Appendix Section 3.1.2.2.9)

B.3.1)

Steam Generator Loss of section Plant specific None Consistent with

feedwater thickness due to GALL, which

impingement plate erosion recommends further

and support evaluation. (See

Item Number Section 3.1.2.2.10)

3.1.1-17

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Component Groupr : "Aglng Effect/ I In"LR"'" o UP ff .MPInGALLoYr'. E itn

.' '.z*7'.Mechanism' .sf< ( . ! . i -Repo t byi-m Ad * ;r d -

Alloy 600 Steam Crack initiation and Steam generator Steam Generator Consistent with

Generator tubes, growth due to tubing integrity; program (Appendix GALL, which

repair sleeves, and PWSCC, outside water chemistry B.3.8); Water recommends further

plugs diameter stress Chemistry Control evaluation. (See

Item Number - corrosion cracking Program (Appendix Section 3.1.2.2.11)

3.1.1-18 (ODSCC), and/or B.3.2)

Intergranular (IGA);

. . , . or loss due to

wastage and pitting . corrosion, and

fretting and wear; or

deformation due to

corrosion at tube

support plate

intersections

Tube support lattice Loss of section Plant specific None Consistent with

bars made of. thickness due to - GALL, which

carbon steel , flow-accelerated _ recommends further

Item Number . corrosion (FAC), evaluation. (See

3.1.1-19 -; - ' Section 3.1.2.2.12)

Carbon steel tube Ugament cracking Plant specific' None Consistent with

support plate due 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 C6mbuistion None -Not applicable to -:

feedwater inlet ring due to FAC engineering FNP (See Section

and supports - Steam Generator 3.1.2.2.14)

Item Number feedwater ring

3.1.1-21 -- inspection

Reactor vessel Crack initiation and' Reactor head Inservice Inspection Consistent with

closure studs and growth due to SCC closure studs Program (Appendix GALL, which

stud assembly and/or IGSCC 8.3.1) recommends no

Item number . further evaluation.

3.1.1-21 - , _ (See Section

l _ _ 3.1.2.1 )

CASS pump casing Loss of fracture Inservice Inservice Inspection Consistent with

and valve body toughness due to inspection Program (Appendix GALL, which - Item Number thermal aging B.3.1) recommends no

3.1.1-23. embrittlement further evaluation.

(See Section - '''__'_-_:__- 3.1.2.1)'- '

CASS piping Loss of fracture Thermal aging Inservice Inspection Consistent with

Item Number toughness due to embrittlement of Program (Appendix GALL, which

3.1.1-24 . thermal aging - CASS B.3.1) recommends no

embrittlement further evaluation.'

(See Section -

. 3.1.2.1) :.

.3-87
I 1.

Component Group, < Aging Effect P:- In GALL:Z ^ 4-- M In L A PStaff Eauilon ___________ 7- Mechandism -, i i Report.U ; §-j - A f >wa

BWR piping and Wall thinning due to FAC None Consistent with

fittings; Steam FAC GALL, which

Generator recommends no

components further evaluation.

Item Number (See Section

3.1.1-25 3.1.2.1)

RCPB valve closure Loss of material Bolting integrity Inservice Inspection Consistent with

bolting, manway due to wear; loss of Program (Appendix GALL, which

and holding bolting, preload due to B.3.1) recommends no

and closure bolting stress relaxation; further evaluation.

in high-pressure crack initiation and (See Section

and high- growth due to cyclic 3.1.2.1)

temperature loading and/or SCC

systems

Item Number

3.1.1-26

CRD nozzle Crack initiation and Nickel-alloy Inservice Inspection Consistent with

Item Number growth due to nozzles and Program (Appendix GALL, which

3.1.1-35 PWSCC penetrations; B.3.1); NiCrFe recommends no

water chemistry Component further evaluation.

assessment Program (See Section

(Appendix B.5.8); 3.1.2.1) Water Chemistry

Control Program

(Appendix B.3.2)

Reactor vessel Crack initiation and Inservice Inservice Inspection Consistent with

nozzles safe ends growth due to cyclic inspection; water Program (Appendix GALL, which

and CRD housing; loading, and/or SCC chemistry B.3.1); NiCrFe recommends no

reactor coolant and PWSCC Component further evaluation.

system components Assessment Program (See Section

(except CASS and (Appendix B.5.8); 3.1.2.1)

bolting) Water Chemistry

Item Number Control Program

3.1.1-36 (Appendix B.3.2)

Reactor vessel Loss of fracture Thermal aging Reactor Vessel Consistent with

internals CASS toughness due to and neutron Intemals Program GALL, which

components thermal aging, irradiation (Appendix B.5.1) recommends no

Item Number neutron irradiation embrittlement further evaluation.

3.1.1-37 embrittlement, and (See Section

void swelling 3.1.2.2.6)

Extemal surfaces of Loss of material Boric acid Borated Water Consistent with

carbon steel due to boric acid corrosion Leakage Assessment GALL, which

components in corrosion and Evaluation recommends no

reactor coolant Program (Appendix further evaluation.

system pressure B.3.5) (See Section

boundary 3.1.2.1)

Item Number

3.1.1-38

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,6Componerit'Groups ; 3APriGALL. i n' .- P IRA aff' Evaluatl '-

- w..'. - "_ . ,-. '; 8'-- Mec'hanIsm~ .4'Report;:.-, J f ---

Steam generator - Loss of material Inservice None - Consistent with "

secondary due to erosion inspection' GALL,'which

manways and recommends no

handholds (carbon, further evaluation.

steel) (See Section -

Item Number 3.1.2.1)

3.1.1-39 .

Reactor internals, Loss of material Inservice- Inservice Inspection Consistent with

reactor vessel due to wear Inspection Program (Appendix GALL, which

closure studs, and 8.3.1); Flux Detector recommends no'

core support pads Thimble Tube further evaluaton.n

Item Number - - _ Inspection Program (See Section

3.1.1-40 - (Appendix B.5.2) 3.1.2.1) ;

Pressurizer integral Crack initiation and Inservice Inservice Inspection Consistent with ''

support ; growth due to cyclic inspection Program (Appendix GALL, which

Item Number loading _ B.3.1) recommends no '

3.1.1-41 further evaluation.-

(See Section

.. __ __ .3.1.2.1)

Upper and lower Loss of preload due Inservice Inservice Inspection Consistent with

internals assembly to stress relaxation inspection; loose Program (Appendix GALL, which

(Westinghouse) part and/or '' .3.1) recommends no&-

Item Number' neutron noise- further evaluation.

3.1.1-42 - - monitoring (See Section

-_____:-_-.___-;_::3.1.2.2.9)

Reactor vessel -Loss of fracture PWR vessel Reactor Vessel Consistent with -

internals in fuel toughness due to intemals; water Iniernals Program '*GALL, which

zone region (except neutron irradiation chemistry (Appendix B.5.1); recommends no

Westinghouse and embrittlement and . Water Chemistry further evaluation.

B&W baffle/former void swelling Program (Appendix (See Section

bolts) .. 3.2) 3.1.2.1)

Item Number

3.1.1-43 '

Steam generator Crack initiation and Inservice Inservice Inspection Consistent with

upper and lower growth due to SCC, inspection; water Program (Appendix 'GALL, which

heads, tubesheets, PWSCC, and/or chemistry B.3.1); NiCrFe recommends no

and primary nozzles IASCC Component -further evaluation.

and safe ends Assessment Program (See Section

Item Number (Appendix B.5.8); 3.1.2.1)

3.1.1-44 Water Chemistry

-' ' ' 'Control Program

(Appendix B.32)

Vessel internals - Crack initiation aad PWR vessel Reactor Vessel' Consistent with

(except growth due to SCC interials; water Internals Program - GALL, which"'

Westinghouse and and IASCC chemistriy^ (Appendix B.5.1);- recommends no

B&W baffle/former Water Chemistry further evaluation.

bolts) Program (Appendix (See Section

Item Number . 3.32)- 3.12.1)

3.1.1-45 '

3-89
'Com'i;n'ent Group~ ~z~'\ Aging EffectI. ;-AMP In GAL 4 LA^'' Saf i " ..t :'Mechanism"'. " - t 

Reactor internals Loss of preload due Inservice None Consistent with

(B&W screws and to stress relaxation inspection; loose GALL, which

bolts) part monitoring recommends no

Item Number further evaluation.

3.1.1-46 (See Section

3.1.2.1)

Reactor vessel Loss of material Reactor head Inservice Inspection Consistent with

closure studs and due to wear, closure studs Program (Appendix GALL, which

stud assembly B.3.1) recommends no

Item Number further evaluation.

3.1.1-47 (See Section

'_ 3.1.2.1)

Reactor internals Loss of preload due Inservice Inservice Inspection Consistent with

(Westinghouse to stress relaxation inspection; loose Program'(B.3.1); GALL, which

upper and lower part monitoring Reactor Vessel recommends no

internal assemblies, Internals Program further evaluation.

CE bolts and tie (Appendix B.5.1) (See Section

rods) 3.1.2.1)

Item Number

3 .1.1-4 8 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

The staff's review of the applicant's reactor vessel, internals, and RCS and associated

components followed one of several approaches'.' One approach, documented in Section

:3.1.2.1, involved the staff's review of the AMR results for components and component groups in

the reactor vessel, internals, and RCS that the applicant indicated are consistent with the GALL

Report and do not require further evaluation. Anrother approach, documented in Section

.3.1.2.2, involved the staff's review of the AMR results for components and component groups in

the reactor vessel, internals,; and RCS that the applicant indicated are consistent with the GALL

Report and for which further evaluation is recommended. A third approach, documented in

Section 3.1.2.3, involved the staff's review of the AMR results for components and component

groups in the reactor vessel, internals, and RCS that the applicant indicated are not consistent

with the GALL Report or are not addressed in the GALL Report. Section 3.0.3 of this SER

documents the staff's review of AMPs that the applicant credited to manage or monitor aging

effects of the RCS components.

.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 Sections 3.1.2.1.1 through 3.1.2.1.4 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 and RCS components:

* Inservice Inspection Program

* Water Chemistry Control Program

* Reactor Vessel Surveillance Program-

* Borated Water Leakage Assessment and Evaluation Program

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I
* Steam Generator Program -

* Reactor Vessel Internals Program

* Flux Dete'ctor Thimble Tube Inspectiodn'Program

* One-Time Inspection Program

* NiCrFe Component Assessment Program

Staff Evaluation

In Tables 3.1.2-1 through 3.1.2-4 of the LRA, the applicant summarized the AMRs for the

reactor vessel internals and RCS 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 staff also identified severalareas wh6re it needed additional information or

clarification. The following describes the staff's evaluation of the applicant's responses to those

RAls.

3.1.2.1.1 'Crack Initiation and Growth Due to Cyclic Loading, and/or Stress-Corrosion Cracking

and Primary Water Stress-Corrosion Cracking (Table 3.1.1, Item 3.1.1-36)'- --

In Table 3.1.2-3 of the LRA, the applicant did not credit the Inservice Inspection Program to

manage cracking 'of non-Class 1 piping and valvedcomponents. However, Table 3.1 ;1,

Item 3.1.1-36, of the LRA (linked to the non-Class 1 piping and valve bodies) states the

following:

* The AMR results are consistent with this summary item. Consistent with NUREG-1801, the water

chemistry program and ISt program will manage cracking of these components. -

The staff noted the inconsistency between Table 3.1.1 and Table 3.1.2-3 of the LRA and

requested that the applicant explain whether it credited the Inservice Inspection Progra 'forthe

non-Class 1 piping and valve bodies and, if it did credit the Inservice Inspection Program, to

correct the inconsistency between the two tables.- The staff identified this issue as RAI 3.0-1A.

By letter dated April 16, 2004, the applicant provided its response to RAI 3.0-1 A. In its

response, the applicant stated that it did not credit the Inservice Inspection Program for ,'

managing cracking of non-Class 1 piping and valve' components. For clarity, the applicant

stated that the second paragraph of the discussion text contained in Table 3.1.1, Item 3.1.1-36,

of the LRA should have read as follows: ' .

While the water chemistry control program and the Inservice inspectioh-program are credited,

inservice inspection for this group Is primarily directed at welded connections in' ASME Class 1

components. The water chemistry control program alone will manage cracking of the non-welded - portions of ASME Class 1 components/component types within this group and all nonASME Class 1 components/component types within this group. -

This is consistent with the GALL Report, Volume 2, Section IV.C2, which recomm'ends ISI and

water chemistry control for Class 1 components but only water chemistry control for non-

'3-91
I

Class 1 components. This is also consistent with other non-Class 1 components in the same

material-environment combination for systems in the GALL Report, Volume 2, Chapter V.

Based on the above discussion and review of the applicant's response, the staff finds that this

line item is acceptable.

On the basis of its review, the staff determined that for AMRs not requiring further evaluation,

as identified in Table 3.1.1 of the LRA (Table 1), the applicant's references to the GALL Report

are acceptable and no further staff review is required. The FNP Audit and Review Report

documents the details of the staff's audit and review.

On the basis of its review, the staff has evaluated the applicant's claim of consistency with the

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging for

these components will be adequately managed so that their intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.1.2 Loss of Fracture Toughness Due to Thermal aging Embritttlement (Table 3.1.1, Item

3.1.1-24)

In Table 3.1.1, Item 3.1.1-24 of the LRA, the applicant states that no program is required to

manage loss of fracture toughness of the FNP reactor coolant system cast austenitic stainless

steel piping and fittings due. to thermal aging embrittlement. In Section 4.5.2 of the LRA, the

applicant states that it has updated the original leak before break analyses to address the

period of extended operation., The results of this calculation update indicate that adequate

toughness remains to ensure that an adequate margin exists between the critical crack size and

the postulated crack size that yields a detectable leak rate.

The staff acknowledges that updating the leak-before-break analyses validates and

demonstrates that the leak-before-break is acceptable for the period of extended operation.

However, the leak-before-break analyses do not demonstrate that the effects of aging will be

adequately managed in accordance with the requirements of 10 CFR 54.21 (a)(3). The GALL

Report recommends that either enhanced volumetric examination or flaw tolerance evaluation

be performed to manage the aging effects for CASS components.

The staff requested that the applicant provide a justification for leak-before-break analyses as

the flaw tolerance evaluation which manages this aging effect. Otherwise, the applicant is

requested to identify which alternative, enhanced Volumetric examination or flaw tolerance

evaluation will be used to manage this aging effect during the period of extended operation.

By letter dated August 19, 2004 (SNC Letter No. NL-04-1486), the applicant provided its

supplemental information to the LRA. In its response, the applicant stated that, consistent with

GALL Report, it will use enhanced volumetric examination or a flaw tolerance evaluation to

demonstrate that CASS piping components potentially susceptible to thermal embrittlement

have adequate fracture toughness.

The applicant further stated that in LRA Table 3.1.2-3, the CASS "Piping, Class 1 (Reactor

Coolant Loop)" component type is revised to include loss of fracture toughness as an aging

effect in the borated 'water environment. The associated NUREG-1 801 Volume 2 Item is

"IV.C2.1-f" and the Table I Item is '3.1-24." The staff reviewed the applicant's response, found

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11
the response consistent with the GALL report recommendation and, therefore, is acceptable.

3.1.2.1.3 Loss of Fracture Toughness Due to Thermal Aging, Irradiation Embrittlement, and

Void Swelling (Table 3.1.1, Item 3.1.1-37)

In reviewing Item 3.1.1-37 of the LRA, the staff noted that the applicant took an exception and

applied a higher threshold value for neutron fluence effects on stainless steel than does the

GALL Report. However, this exception is not identified in Appendix B.5.1, "Reactor Vessel

Internals Program," of the LRA.

In RAI 3.1-1, the staff requested that the applicant submit justification for using the higher

neutron threshold value. In its response to RAI 3.1-1, by letter dated March 5, 2004, the

applicant stated that SNC applies a threshold value for neutron fluence effects on stainless

steels of lx1i021 n/cm2 (E>0.1 MeV). This value is consistent with WCAP-1 4577-A, Revision 1,

"License Renewal Evaluation: Aging Management of Reactor Internals," dated March 2001,

which has been accepted by staff. The applicant further stated that the reactor vessel internal,

components with the highest neutron fluence are considered to have the highest susceptibility

to irradiation induced degradation and therefore 'are the leading indicators for inspection. The

reactor vessel internals program (AMP B.5.1)'provides for inspection and monitoring of these

leading locations.

The staff finds the applicant's response acceptable because the staff has accepted the higher

neutron fluence value for stainless steel as identified in WCAP-14577A, Revision 1, dated

March 2001, and the applicant did include components with the highest fluence value in the

reactor vessel internals program for inspection and monitoring.

Conclusion

The staff has evaluated the applicant's claim of consistency with GALL Report. The staff has

also reviewed information'pertaining to the applicant's consideration of recent operating

experience aind proposals for managing associated aging effects. On the basis of its review,

the staff finds'that the applicant has demonstrated that the effects of aging for these'

components will be adequately managed so that their intended functions will be maintained

consistent with the'CLB for the period of extended operation, as required by .

10 CFR 54.21 (a)(3).

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

Is Recommended

Summary of Technical Information in the ApDlication

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 how it will manage the following aging effects:

* cumulative fatigue damage

* loss of material due to pitting and crevice corrosion

3-93'
* loss of fracture toughness due to neutron irradiation embrittlement

* crack initiation and growth due to thermal and medical loading or stress-corrosion

cracking

* crack growth due to cyclic loading

* changes in dimension due to void swelling

* crack initiation and growth due to stress-corrosion cracking or PWSCC

* crack initiation and growth due to stress-corrosion cracking or IASCC

* loss of preload due to stress relaxation

* loss of section thickness due to erosion

* cracking initiation and growth due to PWSCC, ODSCC, 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

* loss of section thickness due to flow-accelerated corrosion

* ligament cracking due to corrosion

* loss of material due to flow-accelerated corrosion (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 analysis to determine whether it adequately

addressed these issues. 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 FNP Audit and Review

Report documents the details of the staff's audit and review.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections of this SER.

3.1.2.2.1 Cumulative Fatigue Damage

As stated in the SRP-LR, fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs 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.

3.1.2.2.2 Loss of Material 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

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II
corrosion could occur in the SG shell ass mbly.-he 'existing program relies on control of water

chemistry to mitigate corrosion and ISI to 'dtect the'loss of material. The extent and schedule

of the existing SG inspections ensure that'flaws cannot attain a depth sufficient to threaten the

integrity of the welds. However, according to 'NRC IN 90-04, "Cracking of the Upper Shell-to-'

Transition Cone Girth Welds in' Stearm Generators;'dated January 26,;1990, if pitting and

crevice corrosion of the shell exists, the' prograrriirafy not be sufficient to detect pitting and

corrosion. The GALL Report recommends augmented inspections to manage this aging effect.

This IN also identifies operating experience with the pitting of Westinghouse SG models 44 and

51.

FoFmanaging the aging of SG assembliesidue to'ppitting and crevice corrosion, the GALL

Report recommends the' ASME Code, Section Xl,jnservice Inspection, Subsections IWB, IWC,

and IWD (XI.M1) program to detect the loss of material and the water chemistry (XI.M2)

program to mitigate corrosion. The GALL Report recommends a plant-specific program to

conduct augmented inspections.

In LRA Table 3.1.2-4, page 3.1-79, for upper shells lower shells, and transition cone -;

component type, the applicanit'haiscredited Wat6FChernistry Control Program alone for the' loss

of material aging effect. The'LRA also references GALL Section IV.D11 -c, Table 1, Item

3.1.1-2, and note A. Note A is defined as ucoriistent with NUREG- 801 item for component,,

material, environment, and aging effect." AMP is consistent with NUREG-1 801 AMP."

Item IV.Di'.1-c of the GALL Report recommends the water chemistry control program and ISI''1

program to manage the aging effect for losd of riaterial. Thus, note A does not apply.: In

addition, SRP Section 3.1.2.2.2 states"that thbe"combination of the water chemistry control

program and ISI program mayfnot be enough, and augmented inspections may be required. In

LRA Section 3.1.2.2.2, the applicant stated that it uses the Water Chemistry Control Program to

manage the loss of material, but it uses the Inservice Inspection Program to manage cracking.

This section only addresses the loss of material due to pitting and crevice corrosion. The

applicant also stated that no augmented irspections are required because the SGs were'

replaced, and, since then, the applicant has maintained water chemistry per EPRI standards.

However, LRA Section' 3.1.2.2.2 did not state that the'applicant will perform ISI for the'loss of'

material or that it would also use the ISI that is peiformed for managing cracking for the' loss of

material. The'staff requested the applicant to provide clarification during a teleconference on

July 6, 2004, as'documented by the staff inma sburria'ry dated July 20, 2004.

By letter dated July 16, 2004, the applicant provided its supplemental information to LRA

Section 3.1.; In its response, the applicarit stated thatlor the upp6r shells, lower shells,-and

transitionr cones component type, it should not have'applied GALL Report Item'IV.D1 .1-c to

cracking, only to'lo'ss of material. The applicant should havie applied LRA note H to the

cracking' line item instead of notes A and 9. The applicant also stated that for the upper shells,

lower shells, and transition 6ones c'ompone'nt type, it considered crack growth due to cyclic ?

loadinrg as an AERM, with existing ASME Code, Section XI, inspection requirements performed

by the Inservice Inspection Pro'ralmncredited to 'nmanage cracking.' For-the loss of material

associated with the upper shells,'lower shells',,6d transition cones, the AMPs listed should

have included both the Water Chemistry Control Pr6oram and the Inservice Inspection

Program.i Water che'mistry'controls'directlj mitigate the loss'of mate'rial within the SG shell -

assemblies. The Inservice Inspection Prograrmf inspections are not specifically designed to' -

detect the loss of material due to corrosion. However, ASME Code Section Xl 'requirements

:3-95
implemented by the Inservice Inspection Program are designed to identify any flaws large

enough to potentially result in a loss of component intended function, whether caused by

cracking, loss of material, or a combination, of the two aging effects. The Water Chemistry

Control Program alone manages the loss of material associated with these components.

Therefore, the applicant indicated in its response that FNP manages the loss of material of

these components consistently with those specified in GALL Report, Item IV.D1.1-c, and note A

applies. Based on the above discussion, the staff finds that this line item is acceptable.

In IN 90-04, the NRC identified the need to augment inspections beyond the requirements of

ASME Code, Section Xl, if general corrosion pitting of the SG shell is known to exist in order to

differentiate isolated cracks for inherent geometric conditions. The applicant replaced the SGs

at FNP, Units 1 and 2, in 2000 and 2001, respectively, with Westinghouse model 54F

replacement SGs.

The staff reviewed operating experience which indicated that no pitting corrosion of the SG.

shell has been detected to date, and that water chemistry has been maintained for these new

SGs per EPRI guidelines. Since the applicant recently replaced the SGs and has strictly ;

maintained water chemistry per EPRI guidelines, the staff concludes that the applicant has

adequately addressed the management of this aging effect and that augmented inspections are

not required. Sections 3.0.3.2.1 and 3.0.3.1 of this SER discuss the staff's review of the Water

Chemistry Control Program and the Inservice Inspection Program, respectively.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of the loss of material due to pitting and crevice corrosion, as

recommended in the GALL Report. Since the applicant's AMR results are otherwise consistent

with the GALL Reportj the staff finds that the applicant has demonstrated that the effects of,

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

Section 3.1.2.2.3 of the LRA addresses (1) loss of fracture toughness due to neutron irradiation

embrittlement for ferritic materials in the reactor. vessel (RV), as managed using both a plant'

specific AMP and the TLAAs on neutron irradiation embrittlement, and (2) loss of fracture

toughness due to irradiation embrittlement and changes in material properties due to void

swelling.

Section 3.1.2.2.3 of the SRP-LR states that certain aspects of neutron irradiation embrittlement

are TLAAs, as defined in 10, CFR 54.3, and that TLAAs must be evaluated in accordance with

10 CFR 54.21 (c)(1). Section 3.1.2.2.3 also states that the loss of fracture toughness due to

neutron irradiation embrittlement could occur in the reactor vessel. A reactor vessel materials

surveillance program monitors neutron irradiation embrittlement of the reactor vessel. Reactor

vessel surveillance programs are plant specific, depending on matters such as the composition

of limiting materials, availability of surveillance capsules, and projected fluence levels. ,'In:

accordance with Appendix H, "Reactor Vessel Material Surveillance Program Requirerments," to

10 CFR Part 50, an applicant must submit its proposed withdrawal schedule for approval before

implementation. Finally, SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to

neutron irradiation embrittlement and void swelling could occur in Westinghouse and Babcock

and Wilcox (B&W) baffle/former bolts.

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For managing loss of fracture toughhess'due to neujtron irradiation embrittlement in the reactor

vessel, the GALL Report recommends AMP XL.M31, "Reactor V\essel Surveillance," which

complies with the requirements of Appendices G and H to 10 CFR Part 50 and

10CFR Part 50.61.' -

Section 4.2 of the LRA describes the TLAA regarding the loss of fracture toughness due to

neutron irradiation embrittlemrent for ferritic materials that have'a neutron fluence of greater:-

than 1'7n~cr 2.at the end of the license reriewal term.," Section 4.2 of this SER documents the,

staff's review of the applicant's'evaluati6n of this'TLAA. In'performing this review, the stafffollowed the guidance in Section 4.2 of the4SRP-LR. - -

The applicant stated that the Reactor Vessel Surveillance Program (AMP B.3.4), as supportedby associated TLAA'evaluatiohs (Section 4.2 of the LRA), will manage the loss of fracture,-

toughness of reactor vessel beltline compbrients due to irradiatiohneribrittlement by addressing

the'limiting beltline shells 'and welds.' Th6 Reactor Vessel Surveillance Program includes a

capsule withdrawal schedule that providessiuffi6ient'data to assess the effects of irradiation

embrittlement on the beltline components'during the period of extended operation. The - applicant submitted the reactor vessel capsule withdrawal schedule in a'separate LRA .

supplement letter dated December 5,' 2003. Section 3.0.3.2.2 bf this SER addresses the staff's

review of this withdrawal schedule.'

The applicant stated that the loss of fracture toughness due to neutron irradiation embrittlement

and void swelling could occur in Westinghou'se and B&W baffle/former assembly bolts. ,The

GALL Report states that the applicant must provide'a-plant-specific AMP to manage this

potential aging effect.

The applicant credited the Reactor Vessel Inte'rnals Program (AMP B.5.1) with managing the

aging effect of loss of fracture toughness due to neutron irradiation embrittlement and void

swelling. In 1998/1999, the applicantreplaced a number of baffle/former bolts with an improved

design. As summarized in SER Section 3.0.3.2.7, the'applicant has made the following

commitmrients on the Reactor Vessel Internals Program: (1) continued participation in the EPRI

MRP's industry initiatives on degradation of RV internals components, (2) implementation of - those recommended programs and activities that result from these initiatives,-as applicable to - the design of the Farley-RV internals, and'(3) subrmittal of an inspection for the Farley RV

intemals for staff review and approval at least 24 months prior to entering the periods of

extended operation for the FarleVy'u'nits. S6ction 3.0.3.2.7 of this SER documents the staff's

evaluation of the'Reactor Vessel Internals Program.;--

The applicant's commitment for'the Reactor Vessel Internals Program is included in its letter

dated July 27,2004 (SNC Letter No. NL-04-1267). Based on its review of the proposed revised

commitment list, the staff concludes that the applicant has adequately addressed issues related

to change in dimension due to void swelling andloss of fracture toughness due to neutron

irradiation.

On the basis of its review, the staff finds'that'the applicant has appropriately evaluated AMR

results involving management of the loss of fracture toughness due to neutron irradiation

embrittlemrent and void swelling, 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 the effects of aging'will be adequately managed so that the intended

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i

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.1.2.2.4 Crack Initiation and Growth Due to Thermal and Mechanical Loading or StressCorrosion Cracking

In Section 3.1.2.2.4 of the LRA, the applicant addressed the potential for crack initiation and'

growth due to thermal and mechanical loading or stress-corrosion cracking (SCC) (including

intergranular stress-corrosion cracking (IGSCC)) that could occur in small-bore RCS and

connected system piping less than 4 inch nominal pipe size (NPS 4).

Section 3.1.2.2.4 of the SRP-LR states that the GALL Report recommends conducting a plantspecific destructive examination or an NDE that permits inspection of the inside surfaces of the

piping to ensure that cracking has not occurred and the component intended function will be

maintained during the period of extended operation. The applicant should verify that.serviceinduced 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 component intended function will be maintained during the period of

extended operation. Per ASME Code, Section Xi, 1995 Edition, 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 AMP Xl.M1, "ASME Section Xl Inservice Inspection,

Subsections IWB, IWC, and IWD," to detect loss of material and AMP Xl.M2, 'Water

Chemistry," to mitigate SCC.

The applicant credited the Inservice Inspection Program (AMP B.3.1), Water Chemistry Control

Program (AMP B.3.2), and One-Time Inspection Program (AMP B.5.5) to manage the aging

effects of cracking for small-bore RCS and connected systems piping. The staff evaluated

these programs in Sections 3.0.3.1, 3.0.3.2.1, and 3.0.3.1 of this SER, respectively. In addition,

this group of programs is consistent with the group of programs recommended by the GALL.'

Report. The applicant submitted a risk-informed ISI (RI-ISI) program for NRC approval in July

2003. By letter dated March 9, 2004, the staff approved the. RI-ISI program. The risk-informed

methodology will be used to select the small-bore Class 1 butt weld locations for the one-time

volumetric examinations, but it will not be used to eliminate small-bore Class 1 butt welds from

the scope of these one-time examinations. During a teleconference on June 23, 2004, the staff

requested supplemental information in reference to LRA Section 3.1.2.2.4 and the

corresponding item 7 in LRA Table 3.1.1. The staff specifically requested the applicant to

provide the number of ASME Code, Class 1 small-bore piping weld locations that are in the

scope of the LRA under RI-ISI that will be volumetrically examined.

By letter dated July 9, 2004, the applicant provided its supplemental response to LRA Section

3.1.2.4. In its response, the applicant stated that the RI-ISI program includes volumetric ..

examination of one ASME Code, Class 1, small-bore (defined as piping less than NPS 4) piping

seginent per unit, specifically, the 2-inch drainline that tees off of the 3-inch nominal letdown

line in each unit. The applicant stated that the 2-inch circumferential butt weld at the tee in

each unit is scheduled for ultrasonic examination under the RI-ISI program. The applicant

further stated that the One-Time Inspection Program will provide examination of small-bore

ASME Class 1 piping to confirm that cracking (due to thermal cycling or SCC) is not occurring

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in these lines. As a clarification, the applicant stated that examinations performed under the

RI-ISI program that permit inspection of the inside surfaces (e.g., volumetric examination) of the

small-bore ASME Class 1 piping will be included as part of the -representative sample for the

One-Ti'me Inspection Program as applicable7.'Based on the above discussion, the staff finds

that this linelitem is acceptable.

On'the basis of its review, the staff concludes that the applicant has appropriately evaluated

AMR results involving the management of crack initiation and growth due to thermal and -

mechanical loading or SCC for'smrall-b6re'RCS and connected system piping, as

recornmended in the GALL' Report.; Since theiapplicant's AMR results are otherwise consistent

with the GALL Report,'the staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as requitied by 10 CFR 54.21 (a)(3).

3.1.2.2.5 Crack Growth' Due to Cyclic Loading

In Section 3.1.2.2.5 of the LRA, the applicant'addressed crack growth due to cyclic loading that

could occur in reactor vessel shell and RCS piping and fittings.

Section 3.1.2.2.5 of the SRP-LR states 'that growth of intergranular separations (underclad

cracks) in low-alloy or carbon steel heat-affected zones under austenitic stainless steel cladding

'is a TLAA to be 6valuated for the period of extended operation for all the SA 508-Class 2 -

forgings where the cladding was deposited with'a high heat input welding process. The

methodology for evaluating the underclad flaws should be consistent with the current wellestablished flaw evaluation procedure and criterion in ASME Code, Section Xl. The GALL

Report recommends further evaluation of programs to manage crack growth due to cyclic*-

loading in RV shell and RCS piping and fittings.:i

In Section 3.1.2.2.5 of the LRA, the applicant stated that underclad cracking of reactor vessel

and RCS clad alloy steel forgings is not a-TLAA for FNP. The applicant stated that all clad alloy

steel forgings are not SA 508-Class 2, or they did not use a high heat input welding process for

clad deposition. The applicant stated that the reactor vessel shells were fabricated from

SA-533, Grade B, plates. Moreover, the applicant has not identified any underclad cracking at

FNP.

The staff reviewed Section 3.1.2.2.5 of the LRA and agreed that underclad cracking is not an

applicable aging effect for these forgings, 'since 'they are not madeof SA 508-Class 2 material,

or the high heat input welding processes affecting underclad cracking (i.e., strip clad and

manual inert gas cladding processes) were not used to apply cladding to these components.

3.1.2.2.6 Changes in Dimension Due to Void Swelling -

In Section 3.1.2.2.6 of the LRA, the applicant addressed changes in dimension due to void

swelling that could occur in reactor internal components.

Section 3.1.2.2.6 of the SRP-LR states that the GALL Report recommends evaluation of

changes in dimension due to void swllin'g'in react6r internal components to ensure that this

aging effect is adequately'managed. The GALL' Report recommends evaluation of a -:

plant-specific AMP to manage the effects of chianges'in dimension due to void swelling and the

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I

loss of ductility associated with swelling.

The applicant credited the Reactor Vessel Internals Program (AMP B.5.1) to manage changes

in material properties due to void swelling, which could occur in the PWR reactor vessel

internals. The applicant stated that this new program is consistent with GALL AMP XI.M1 6,

"PWR Vessel Internals." The applicant considered the baffle/former assemblies, including

baffle/former bolting, to be leading indicators for void swelling. Section 3.0.3.2.7 of this SER

documents the staff's evaluation of the Reactor Vessel Internals Program. The applicant

further stated that it will continue to participate actively in industry efforts to quantify the nature

and extent of void swelling in the PWR environment. The applicant will update the Reactor

Vessel Internals Program based upon the results of these industry initiatives.

As summarized in SER Section 3.0.3.2.7, the applicant has made the following commitments

on the Reactor Vessel Internals Program: (1) continued participation in the EPRI MRP's

industry initiatives on degradation of RV internals components; (2) implementation of those

recommended programs and activities that result from these initiatives, as applicable to the

design of the Farley RV internals, and (3) submittal of an inspection for the Farley RV internals

for staff review and approval at least 24 months prior to entering the periods of extended

operation for the Farley units. The staff evaluates these commitments in Section 3.0.3.2.7 of

this SER. Section 3.0.3.2.7 of this SER provides the staff's evaluation of the licensee

commitments on the RV internal components (including baffle/former bolts), and the staff's

basis for concluding that the applicant's commitments for the Reactor Vessel Internals Program

are adequate to manage void swelling in these components.

On the basis of its review and the applicant's commitments discussed and evaluated in Section

3.0.3.2.7 of this SER, the staff finds that the applicant has appropriately evaluated AMR

results involving the management of changes in dimension and material properties due to void

swelling in the baffle/former plates, 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 the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.1.2.2.7 Crack Initiation and Growth Due to Stress-Corrosion Cracking or Primary Water

Stress-Corrosion Cracking

In Section 3.1.2.2.7 of the LRA, the applicant addressed (1) crack initiation and growth due to

SCC and PWSCC that could occur in core support pads (or core guide lugs), instrument tubes

(bottom head penetrations), pressurizer spray, heads, and nozzles for the SG instruments and

drains; (2) crack initiation and growth due to SCC that could occur in CASS RCS piping and

fittings and pressurizer surge line nozzles; and (3) crack initiation and growth due to PWSCC

that could occur in pressurizer instrumentation penetrations and heater sheaths and sleeves

made of nickel alloys.

Section 3.1.2.2.7 of the SRP-LR provides the following three criteria:

(1) Crack initiation and growth due to SCC and PWSCC could occur in core support pads

(or core guide lugs), instrument tubes (bottom head penetrations), pressurizer spray

heads, and nozzles for the SG instruments and drains. The GALL Report recommends

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1I
further evaluation to ensure that these'aging effe6ts are6adequately managed. The'

GALL Report recommends evaluation of a plant-specific AMP because existing

programs may not be capable of mitigating or detecting crack initiation and growth due

to 5CC.

(2) Crack initiation and growth due to SCC could occur in RCS piping and fittings and CASS

pressurizer surge line nozzles. The GALL Report recommends further evaluation of - piping that does not meet either the reactor water chemistry guidelines of EPRI

TR-105714, "PWR Primary Water Chemistry Guidelines," or material guidelines of

NUREG-0313, 'Technical Report on MaterialSelection and Processing Guidelines for

BWR Coolant Pressure Boundary Piping.

(3) Crack initiation and growth due to PWSCC could occur in pressurizer instrumentation

penetrations and heater sheaths and sleeves made of nickel alloys. The existing: -:

program relies on ASME Code,- Section Xl, ISI and on control of water chemistry to

mitigate PWSCC. Howev6r, 'the existing program should be augmented to manage the

effects of SCC on the intended function of nickel-alloy components. The GALL Report

recommends that the applicarit pr6vide a plant-specific AMP or participate in industry

programs-to determine appropriate'AMPs for PWSCC of the Alloy 182 weld.; '

The applicant credited the following plant-specific programs for each of the three SRP-LR

criteria: . -

(1) The applicant will use a combination of the Water Chemistry Control pr6grrn and the '

NiCrFe Component Assessment Program.' If augmented inspections are required, then

the applicant will incorporate these inspections into the Inservice Inspection Programr. ' The GALL AMP XI.M1 1, "Nickel-Alloy Nozzles and Penetrations," for NiCrFe alloy

material includes an assessment and use of ISI for inspection.

(2).- The applicant will use the Water Chemistry Control Program to mitigate the effects of

cracking due to'SCC. -The program implements the guidance contained in EPRI'

_TR-1 05714 and is consistent with the GALL Report.

(3) The pressurizer instrunientation penetrations and heater sheaths and sleeves are*

fabricated from stainless steel material at FNP; therefore, this criterion does not apply to

FNP..

Crack lnitiation and Growth Due to SCC and PWSCC -

In Section 3:1.2.2.7.1, of the LRA, the applicant included two nickel alloy components, core'

support lugsiand bottom head penetration~s. The applicant credited (1) the NiCrFe Component

Assessment Program (AMP B.5.8), (2) the Water Chemistry Control Program (AMP B.3.2) and,

(3) if the assessment shows that augmented inspection requirements are required, the

Inservice Inspection Program (AMP B.31) tormanage crack initiation and growth du6e to'

PWSCC of these components.

Sections 3.0.3.3.3, 3.0.3.2.1, and 3.0.3.1 of this SER document the staff's evaluation of the

NiCrFe Component-Assessinent Program, Water Chemistry Contral Program' and Inserviide

Inspection Program, respectively. The GALL AMP Xl.M1 1 program for NiCrFe alloy material

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includes an assessment and use of ISI for inspection. The staff concluded that the NiCrFe

Component Assessrment Program and the lnservice Inspection Program are similar to the

GALL Report AMP XI.M1 i program, which includes an assessment and uses the ISI program

for detection of aging effects, if required. Therefore, the programs are acceptable. The staff

also concluded that the Water Chemistry Control Program is acceptable since the program

implements the guidance contained in EPRI TR-1 05714 and is consistent with the GALL

Report.

Crack Initiation and Growth Due to SCC'

The applicant conservatively includes AMR of'the pressurizer spray head by crediting the water

chemistry control program (AMP B.3.2) and the one-time inspection program (AMP B.5.5) to

manage cracking initiation and growth due to SCC. This is acceptable since the spray head is

not within the scope of license renewal based on the Westinghouse'Comrriercial Atomic Power

(WCAP) 14574-A, "License Renewal Evaluation: Aginig Manage ment Evaluation for

Pressurizers," dated December 2002. The NRC staff has accepted this basis.'

The applicant credited the Water Chemistry Control Program (AMP B.3.2) to manage crack

initiation and growth due to in CASS RCS piping and fittings. 'CC The program implements

the guidance contained in EPRI TR-105714.

Section 3.0.3.2.1 of this SER documents the staff's evaluation of this program. Since the

applicant's AMR for the CASS components indicated that the primary water chemistry is

maintained in accordance with the chemistry guidelines of EPRI TR-1 05714, Revision 3, the

staff concludes that the AMR for' the CASS components is consistent with the GALL Report and

is, therefore, acceptable.

Crack Initiation and Growth Due to PWSCC in Pressurizer Instrumentation Penetrations and

Heater Sheaths and Sleeves Made of Nickel Alloys

The applicant stated that the pressurizer instrumentation penetrations and heater sheaths are

made of austenitic stainless steel and are not susceptible to`PWSCC. The staff reviewed

Section 3.1.2.2.7 of the LRA and concludes that the pressurizer instrument penetrations and

heater sheaths are fabricated from austenitic stainless steel and not nickel alloys and,

therefore, the applicant's approach is acceptable.

On the basis of its review, the staff concludes that the applicant has adequately evaluated the

management of crack initiation and growth due to SCC or PWSCC for RCS components

discussed in this section. Based on this conclusion,' and the confirmation that the' remainder of

the applicant's program is consistent with the GALL Report, the staff concludes that this aging

effect will be adequately managed during the period of extended operation, as required by 10

CFR 54.21 (a)(3).

3.1.2.2.8 Crack Initiation and Growth Due to Stress-Corrosion Cracking or Irradiation-Assisted

Stress-Corrosion Cracking

In Section 3.1.2.2.8 of the LRA, the applicant addressed crack initiation and growth due to SCC

or IASCC that could occur in baffle/former assembly bolts in the reactor internals.

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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 assembly bolts in Westinghouse and B&W reactors. The GALL

Report recommends further evaluation to ensure that these aging effects are adequately

managed.

The applicant credited the Reactor Vessel Internals' Program (AMP B.5.1) 'and the Water

Chemistry Control Program (AMP B.3.2) to manage these aging effects. The'applicant recently

replaced these bolts, and testing of the replaced bolts indicated that no significant degradation

had occurred. "The applicant stated that since the bolts were replaced, it would expect to see

the lower end of life fluence,'and with the improved stress profile and excellent operating history

to date, the-applicant does not plan to perform any volumetric inspection.

The GALL Report states that the industry is currently addressing the issue of baffle bolt

cracking in the PWR MRP ITG activities to determine, develop, and implement the necessary

steps and plans to manage the applicable aging effects on a plant-specific basis. -

As summarized in SER Section 3.0.3.2.7, the applicant has made the following commitments

on the Reactor-Vessel Internals Program: (1) continued participation in the EPRI MRP's

industry initiatives on degradation of RV internals components, (2) implementation of those

recommended programs and activities that result from these initiatives, as applicable to the

design of the Farley RV internals, 'and (3) submittal of an inspection for the Farley RV internals

for staff review and approval at least 24'months prior to entering the periods of extended -

operation for the Farley units. Section 3.0.3.2.7 of this SER provides the staff's evaluation of

the licensee commitments on the RV internal components (including baffle/former bolts), and

the staff's basis for concluding that the'applicant's commitments for the Reactor Vessel

Internals Program are adequate to manage cracking in these components.

The staff evaluates the Water Chemistry Control Program in Section 3.0.3.2.1 of this SER and

the Reactor Vessel Internals Program in Sectiori 3.0.3.2.7 of this SER.

On the basis of its review and the applicant's commitments discussed and evaluated in Section

3.0.3.2.7 of this SER, the staff finds that the applicant has appropriately evaluated AMR

results involving the management of crack initiation and growth due to SCC or IASCC for the

baffle/former plates, 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 the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

In Section 3.1.2.2.9 of the LRA, the applicant addressed the loss of preload due to stress

relaxation that could occur in baffle/former assembly bolts in the reactor.

Section 3.1.2.2.9 of the SRP-LR notes that loss of preload due to stress relaxation could occur

in baffle/former assembly bolts. The GALL Report states that the applicant must provide a

plant-specific AMP to manage this potential aging effect.

The applicant credited the Reactor Vessel Internals Program (AMP B.5.1), in combination with

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visual inspections performed under the Inservice Inspection Program (AMP B.3.1), to manage

the aging effect of loss of preload due to stress relaxation in baffle/former assembly bolts. The

applicant stated that it replaced these bolts at FNP; during the replacement project, the

applicant did not note any indications of significant stress relaxation.

As summarized in SER Section 3.0.3.2.7, the applicant has made the following commitments

on the Reactor Vessel Internals Program: (1) continued participation in the EPRI MRP's

industry initiatives on degradation of RV internals components, (2) implementation of those

recommended programs and activities that result from these initiatives, as applicable to the

design of the Farley RV intemals; and (3) submittal of an inspection for the Farley RV internals

for staff review and approval at least 24 months prior to entering the periods of extended

operation for the Farley units. Section 3.0.3.2.7 of this SER provides the staff's evaluation of

the licensee commitments on the RV internal components (including baffle/former bolts), and

the staff's basis for concluding that the applicant's commitments for the Reactor Vessel

Internals Program are adequate to manage loss of preload due to stress relaxation in these

components.

The staff evaluates the Inservice Inspection Program in Section 3.0.3.1 of this SER and the

Reactor Vessel Internals Program in Section 3.0.3.2.7 of this SER.

On the basis of its review and the applicant's commitments discussed and evaluated in Section

3.0.3.2.7 of this SER, the staff finds that the applicant has appropriately-evaluated AMR

results involving the management of the loss of preload due to stress relaxation, 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 the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.2.10 Loss of Section Thickness Due to Erosion

In Section 3.1.2.2.10 of the LRA, the applicant addressed the loss of section thickness due to

erosion that could occur in SG feedwater impingement plates and supports.

Section 3.1.2.2.10 of the SRP-LR states that the loss of section thickness due to erosion could

occur at the feedwater impingement plates and supports in the SGs. The GALL Report

recommends further evaluation of the effectiveness of the applicant's plant-specific AMP to

ensure that this aging effect is adequately managed.

The applicant stated that its SGs have a recirculating feedring design that includes an elevated

feedring and feedwater spargers. The SGs do not use impingement plates. Therefore, the loss

of section thickness due to erosion of the feedwater impingement plates and supports is not

applicable to FNP.

3.1.2.2.11 Crack Initiation and Growth Due to PWSCC, ODSCC, or lntergranular 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 Plates

In Section 3.1.2.2.11 of the LRA, the applicant addressed crack initiation and growth due to

PWSCC, outside-diameter stress-corrosion cracking (ODSCC), or intergranular attack (IGA) or

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loss of material due to wastage and pitting corrosion or deformation due to corrosion that could

occur in nickel-based (NiCrFe) aiioy components of the SG tubes'and plugs.

Section 3.1.2.11 of the SRP-LR states that crack initiation and growth due to PWSCC, ODSCC,

or IGA or loss of material due to wastage and pitting corrosion or deformation due to corrosion

could occur in Alloy 600 components of the SG tubes, repair sleeves, and plugs. All PWR

licensees have committed voluntarily to an SG degradation management program described in

NEI 97-06; the NRC staff is currently reviewing these guidelines. The GALL Report

recommends development of an AMP based on the recommendations of staff-approved NEI

97-06 guidelines, or another alternate regulatory basis for SG degradation management, to

ensure that'this aging effect is adequately managed.

To manage the effects of aging, the applicant credited the Steam Generator Program (AMP

B.3.8) and the'Water Chemistry Control Program' (AMP B.3.2). The applicant stated that its

Steam Generator Program is based on the recommendations of staff-approved NEI 97-06

guidelines and is consistent with GALL Report AMP XI.M1 9, "Steam Generator Tube Integrity."

Sections 3.0.3.1 and 3.0.3.2.1 of this SER document the staff's evaluation of these programs.

In Section 3.1.2.2.11 of the LRA, the applicant stated that it does not consider degradation of

the replacement SG thermally treated Alloy 690 tubes likely based on the improved materials of

construction and design of the replacement Model 54F SGs, but the applicant conservatively

considered such degradation in the AMR results. The applicant has not installed SG tube! -

sleeves-and plugs in the replacement SGs:. However, the applicant will use thermally treated

Alloy 690 should it install any plugs or sleeves. The loss of material due to pitting and wastage

related to phosphate chemistry does not apply because the applicant has not utilized phosphate

chemistry. -However, the applicant conservatively considered localized corrosion of the

thermally treated Alloy 690 SG tubes in the'AMR results. The replacement SGs employ

stainless steel tube support plates and flow distribution baffles. As such, denting of tubes at

support plate intersections is unlikely to occur. However, the applicant conservatively

considered the potential for denting in the AMR results.

Based on the low likelihood of these aging effects, and because the applicant has

conservatively considered these aging effects in the AMR evaluation, the staff concluded that

the Steam Generator Program and the Water Chemistry Control Program will effectively

manage SG tube degradation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving the management of (1) crack initiation and growth due to PWSCC, ODSCC,

and/or IGA, (2) loss of material due to wastage and pitting corrosion, (3) loss of material due to

fretting and wear, or (4) denting due to corrosion of carbon steel tube support plate in the SG

tubes and plugs, as recommended in the GALL Report.;- Since the applicant's AMR results are

otherwise consistent with the GALL Repoft,the staff finds that the applicant has demonstrated

that these aging effects will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). - '

3.1.2.2.12 Loss of Section Thickness Due to Flow-Accelerated Corrosion

In Section 3.1.2.2.12 of the LRA, the applicant addressed the loss of section thickness due to

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FAC that could occur in SG 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

evaluation of a plant-specific AMP and, on the basis of the guidelines of NRC GL 97-06,

development of an inspection program for SG internals to ensure that this aging effect is

adequately managed.

The applicant stated that this aging effect applies only to CE SGs and that its Westinghouse

Model 54F replacement SGs do not use lattice bars. In addition, the tube support plates are

fabricated from FAC-resistant stainless steel. Therefore, this aging effect does not apply to

FNP.

On the basis that the applicant's SG design does not include carbon steel tube support lattice

bars, the staff concludes that this aging effect does not apply to FNP.

3.1.2.2.13 Ligament Cracking Due to Corrosion

In Section 3.1.2.2.13 of the LRA, the applicant addressed the ligament cracking due to

corrosion that could occur in carbon steel components in the SG 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 SG tube support plate. All PWR licensees have committed

voluntarily to an SG degradation management program described in NEI 97-06; the staff is

currently reviewing these guidelines. The GALL Report recommends development of an AMP

based on the recommendations of staff-approved NEI 97-06 guidelines or other alternate

regulatory basis for SG degradation management to ensure that this aging effect is adequately

managed.

The applicant stated that its SG tube support plates are fabricated from stainless steel;

therefore, this degradation mode does not apply.

Because the SG design does not include carbon steel tube support plates, the staff concludes

that this aging effect does not apply to FNP.

3.1.2.2.14 Loss of Material Due to Flow-Accelerated Corrosion (PWR)

In Section 3.1.2.2.14 of the LRA, the applicant addressed the loss of material due to FAC that

could occur in feedwater inlet rings and supports.

Section 3.1.2.2.14 of the SRP-LR states that the loss of material due to FAC could occur in

feedwater inlet rings and supports. As noted in CE IN 90-04, NRC IN 91-19, and Licensee

Event Report 50-362/90-05-01, this form of degradation has been detected only in certain CE

System 80 SGs. The GALL Report recommends further evaluation to ensure that this aging

effect is adequately managed. The GALL Report also recommends evaluation of a plantspecific AMP because existing programs may not be capable of mitigating or detecting the loss

of material due to FAC.

The applicant stated that its replacement SGs are of Westinghouse Model 54F design, for

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which this form of degradation has hot b6een detected. Therefore the components are not

subject to this aging effect.

On the basis that the applicant's replacement SGs are of Westinghouse design, and that the

loss of material due to FAC has been detected only in certain CE System'80 SGs, the staff

concludes that this aging effect does not apply to FNP.

Conclusion

On the basis of its audit and review, the staff finds that the'applicant's further evaluations

conducted in accordance with the GALL Report are consistent with the acceptance criteria in

Section 3.1.2.2 of the SRP-LR. Since the applicant's AMR results are otherwise consistent with

the GALL report, the staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the infen'ded fuicti6n(s) will be maintained consistent with the

current licensing basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3 AMR Results That Are Not Consistent With or Not Addressed in the GALL Report

3.1.2.3.1 Reactor Vessel Aging Management Review Results

3.1.2.3.1.1 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. The applicant identified the following programs that manage the AERMs for the RPV

and associated pressure boundary components:

* Water Chemistry Control Program * Inservice Inspection Program - ' * Reactor Vessel Surveillance Program

* NiCrFe Component Assessment Program,

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.1.2-1 of the LRA, the applicant provided a summary of AMRs for the RPV and

associated pressure boundary componentsT aind idejntified which AMRs it considered to be

consistent with the GALL Report.

3.1.2.3.1.2 Staff Ev'aluationLoss of Material in Austenitic Stainless Steel or Nickel-Based Alloy RV Components Under

ExDosure to the Borated Water Environment

Summary of Technical Information in'the Application'

The applicant identified that loss of nrite'rial is an applicable aging effect for NiCrFe

components and stainless steel RV corfiponehts'that are exposed to borated water -

environments. It categorized its AMR for these components as one for which the GALL Report

has not ideritified the aging' effect for the "material-erivironment conditions for the components

(i.e., note H to Table 3.1.2-1). The scope of thiscomrnmodity group includes the following

components:

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* bottom head torus and dome (low-alloy steel with stainless steel cladding)

* BMI guide tubes (stainless steel)

* BMI penetrations (Alloy 600)

* core exit thermocouple (CET) and heated junction thermocouple closure (HJTC)

assemblies (stainless steel)

* closure head dome and flange (low-alloy steel with stainless steel cladding)

* RV core support lugs (Alloy 600)

* CRDM and instrumentation housing penetration nozzles (thermally treated Alloy 690)

* CRDM housing flange adapters (stainless steel)

* CRDM latch housings and rod travel housings (stainless steel)

* RV head vent penetration (thermally treated Alloy 690)

* intermediate and lower shell courses (low-alloy steel with stainless steel cladding)

* RV leakage monitoring tube assembly (Alloy 600)

* RV primary nozzle safe end (stainless steel with Alloy 82/182 welds and buttering)

* vessel flange (low-alloy steel with stainless steel cladding)

* seal table and fittings (stainless steel).

* upper (nozzle) shell course (low-alloy steel with stainless steel cladding)

* stainless steel cladding for the low-alloy steel or carbon steel RV components that are

clad with austenitic stainless steel

The applicant credited the Water Chemistry Program with the management of loss of material

in these components.

Identification of Aging Effects

The applicant identified that loss of material is an applicable aging effect for NiCrFe

components and stainless steel RV components that are exposed to borated water

environments. These components include carbon steel or low-alloy steel components that are

clad with austenitic stainless steel that is exposed to the borated water environments.

The applicant did not identify in Section 3.1 of the LRA or, in LRA Table 3.1.2-1 which aging mechanisms it considered capable of inducing loss of material in the stainless steel (including

stainless steel clad components) or NiCrFe RV components exposed to borated water. The

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staff required additional information on this matter. >Specifically, for each of these components,

the staff requested that the applicant define which aging mechanism or mechanisms were,

considered to be capable of inducing loss of material in the components. The staff identified

this as RAI 3.1.3.1.1-1, Part a. The'staff also informed the applicant that this RAI also applies

to comparable NiCrFe and stainless steel RV internals components within the scope of Table

3.1.2-2 and comparable NiCrFe and stainless steel piping and pressurizer components within

the'scope of Table'3.1.2-3. Part a of RAI 3.1.3.1.1-1 applies to the following RV components:

* bottom head torus and dome (low-alloy steel with stainless steel cladding)

* BMI guide tubes (stainless steel)

* BMI penetrations (Alloy 600)

* CET and HJTC assemblies (stainless steel)' -

* -closure head dome and flange (low-alloy steel with stainless steel cladding)

* RV core support lugs (Alloy 600)

* 'CRDM and instrumentation housing penetration nozzles (thermally treated Alloy 690)

* CRDM housing flange adapters (stainless'steel)

* ' -'CRDM latch housings and rod travel housings (stainless steel) . -

* -RV head vent penetration (thermally treated Alloy 690)

* intermediate and lower shell courses (low-alloy steel with stainless steel cladding)

* RV leakage monitoring tube assembly (Alloy 600)

* 'RV primary nozzle safe end (stainless steel with Alloy 82/182 welds and buttering)

* vessel flange (low-alloy steel with stainless'steel cladding)

* seal table and fittings (stainless steel) .:.: ,,....:- - . - -. , I - *-h,, >......................................

* upper (nozzle) shell course (low-alloy steel with stainless steel cladding)

* stainless steel cladding for the low-alloy steel or carbon steel RV components that are

-clad with austenitic stainless steel - ,- : 

The applicant provided its response to RAI 3.1.3.1.1-1,IPart a, in SNC Letter.No. NL-04-0617,-

dated April 16, 2004. In its response to the RAI, the applicant confirmed that loss of material

was an applicable aging effect for all the stainless steel and NiCrFe RV components identified

in RAI 3.1.3.1 .1-1, Part a,:and that for all of these components, loss of material due to crevicecorrosion or pitting corrosion was an applicable aging effect/mechanism requiring management.

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The applicant also indicated that it conservatively assumed that loss of material due to wear

was an applicable aging effect/mechanism requiring management for the RV flange.

The staff concludes that the applicant's response to RAI 3.1.3.1.1-1I Part a, is acceptable

because it clarifies which aging mechanisms could induce loss of material for those stainless

steel or NiCrFe RV components identified in LRA Tables 3.1.2-:1; 3.1.2-2, and 3.1.2-3 as

exposed to borated water. Therefore, RAI 3.1.3.1.1-1, Part a, is resolved. Section 3.1.2.3.3, in

the subsection entitled uAging Management Programs or Activities Credited with Aging

Management," provides the staff's assessment of the AMPs credited for managing loss of

material in these components.

Aging Management Programs

With the exception of the vessel flange (a low-alloy steel component with internal stainless steel

cladding), the applicant has credited the Water Chemistry Control Program for the management

of the loss of material that may occur in the NiCrFe and stainless steel RV components

(including low-alloy steel or carbon steel components with stainless steel cladding or inserts)

that are exposed to the borated water environment.

The applicant credited both the Inservice Inspection Program and Water Chemistry Control

Program with the management of the loss of material from-the internal stainless steel cladding

surfaces of the RV flange. The applicant's Inservice Inspection Program is an established AMP

that is based on compliance with the staff's ISI requirements in 10 CFR 50.55a. This program

has appropriate requirements for inspecting the stainless steel cladding surfaces of the RV

flange and is acceptable for inspections of the RV flange and its cladding. Section 3.0.3.1 of

this SER provides the staff's evaluation of the ability of the Inservice Inspection Program to

manage wear in the RV flange and its cladding. As a supplement to the Inservice Inspection

Program, the applicant credited the Water Chemistry Control Program as an additional

mitigative AMP, as recommended for aging management in the AMR for GALL commodity

group IV.A2.5-f. Therefore, the applicant's approach is acceptable. Section 3.0.3.2.1 of this

SER provides the staff's evaluation of the Water Chemistry Control Program.

For other stainless steel or NiCrFe RV components, the staff informed the applicant that AMPs

designed to manage the loss of material depend upon the type of aging mechanism that leads

to the aging effect and that the applicant's Water Chemistry Control Program was not an

inspection-based AMP. Instead, the staff noted that water chemistry programs are based on

mitigative strategies that should reduce the probability that aging effects related to the loss of

material or cracking will occur as a result of aging mechanisms related to chemical reactions or

corrosion. Therefore,-the staff requested that the applicant provide its technical bases for

considering only the Water Chemistry Control Program to be sufficient to manage loss of

material in the components without including an inspection-based AMP to confirm that the

Water Chemistry Program is accomplishing its mitigative function. As an alternative; the staff

requested that the applicant propose an acceptable inspection-based AMP to manage the loss

of material in the'specific RV components within the scope of RAI 3.1.3.1.1-1, Part a. The staff

identified this issue as RAI 3.1.3.1.1-1, Part b.

The applicant provided the following response to RAI 3.1.3.1.1-1, Part b, in SNC Letter No.

NL-04-0617, dated April 16, 2004:

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in the LRA, the FNP Water Chemistry Conirol Prograrn (alone) is credited to manage loss of

material due to the aging mechanisms of crevice corrosion and pitting for all of the components

listed by RAI 3.1.3.1.1-1a. Our rationale follows. Jr,-.-- ii.- 

The wetted surfaces (borated water en'ironmfent) of the components identified in3.13.1.1-1 are

fabricated from stainless'steel and NiCrFe alloys.- For stainless steels and NiCrFe alloys,

penetration of the passive chromium oxide layeriand subsequent corrosion has been shown to be

principally related to the oxidizing nature of the environment and the presence of specific

detrimental ionic species known to interfere with the passivation process; most notably chlorides,

sulfates, and fluorides. ;

The FNP Water Chemistry Control Program is implemented consistent with the EPRI Primary

Water Chemistry Guidelines. This Industry guideline Is the result of extensive industry operating experience, research, and industry consensus. The resulting program provides for both a stronglyI reducing coolant environment via the additiori of o-xygen scavengers such as hydrogen and for

strict control of ionic species. A sufficient residual concentration of hydrogen Is maintained at all -

times to assure the reducing nature of the reactor coolant. Detrimental ionic species such as

chlorides, sulfates, and fluorides are limited to the low ppb range during power operations.

beNP and industry wide operating experience confirm that pitting and crevice corrosion has not

been an issue ofaconcem for reactor coolant system components. FNP inservice inspections.

performed in accordance with Section XI of the ASME Code include numerous inspection locations

consisting of the borated water environment and stainless steel and NiCrFe alloy material

-combinations. - - . '

The aging effects determinations in NUREG-1801 also support this position. NUREG-1801

acknowledges that loss of material due to pitting and crevice corrosion is not an aging effect/mechanism requiring management for stainless steel components exposed to a borated

water environment. Specifically, several sections of NUREG-1801 (e.g.. sections V.D1, VI.A3,

VIL.EI) include a conclusive statement that stainless steel components are not subject to

significant general, pitting, and crevice corrosion in a borated water environment; therefore these

aging mechanisms are'not included in NUREG-1801 for this material and environment - - -

combination. In addition, SNC has not identified any NUREG-1801 recommendation for an

inspection-based AMP to manage loss of material due to pitting and crevice corrosion for stainless

steel and NiCrFe alloys in a borated water environmnent.

Pitting corrosion and crevice corrosion may occur in ASME Code, Class 1, stainless steel or

NiCrFe components under exposure to aggre'ssive, oxidizing environments.' Normally, the

presence of elevated dissolved oxygen and/or aggressive ionic impurity concentrations is -

necessary to create these oxidizing environments in the RCS. The applicant's response to RAI

3.1.3.1.1-1, Part b, provides an acceptable 6xplanation for citing the Water Chemistry Control

Program as a basis for minimizing the dissolved oxygen and ionic impurity concentrations that

could otherwise, if left present in'high conceitrations, lead to an aggressive, oxidizing RCS'

coolant environment. The GALL Report'does not indicate that the loss of material due to pitting

corrosion or crevice corrosion is an aging effect'of concern for stainless steel or NiCrFe ASME

Code Class 1 components. Since the applicant has conservatively assumed that the loss of

material due to pitting 'corrosiondor crevice corrosion is an applicable aging effect'for these RV

components, the staff concludes that the Water Chemistry Control Program provides a

sufficient mitigative'strategy for managing this agi'ng eff ect relative to the recommendations of'

the GALL Report. Section 3.0.3.2.1 of this SER provides the staff's evaluation of the Water

Chemistry Control Program. - - -

In its response to RAI 3.1.3.1.1-1, Part a,'the applicant also confirmed that the RV flange was

the only alloy steel/stainless steel clad component in the RV that could potentially be subject to

loss of material due to wear as a' result of exposure of the stainless steel cladding to the

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borated water environment. Earlier in this section, the'staff discussed, evaluated, and accepted

the applicant's basis and proposed AMPs for managing wear in the RV flange.' In addition to

the RV flange, Section IV.A2 of GALL, Volume 2 (i.e., in GALL commodity group IV.A2.2-f),

also identifies that the stainless bolting in bolted CRDM housing flange designs may be

susceptible to loss of material as a result of wear. However, this commodity group does not

apply to the CRDM housing flange adapters in the FNP designs because the CRDM housing

flange adapters do not involve bolted configurations.

Based on its review of the contents of LRA Table 3.1.2-1, and SNC's responses to RAI

3.1.3.1.1-1, Parts a and b, the staff concludes that the applicant has proposed acceptable

AMPs for managing the loss of material as a result of crevice corrosion, pitting corrosion, and

wear in the stainless steel and NiCrFe RV components. Therefore, RAI 3.1.3.1.1-1, Part b, is

resolved.

The staff has reviewed the applicant's AMRs for evaluating the loss of material in ASME Code,

Class 1, RV components that are made from stainless steel or NiCrFe materials and are

exposed to borated water. The staff concludes that the applicant has credited an acceptable

basis for concluding that its Water Chemistry Control Program is sufficient to manage the loss

of material in these components as a result of pitting corrosion or crevice corrosion. The staff

has also determined that the applicant has credited an acceptable inspection-based AMP (i.e.,

the Inservice Inspection Program) to manage the loss of material in the RV flange as a result of

wear.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

Loss of Material in Low-Alloy Steel or Carbon Steel RV Components That Are Exposed

Externally to Inside (Atmospheric) Environments

Summary of Technical Information in the Application

The applicant identified that loss of material is an AERM for low-alloy steel and carbon steel

components that are exposed externally to the inside (atmospheric) environment. The scope of

this commodity group includes the following components:

* bottom head torus and dome (low-alloy steel with stainless steel cladding)

* closure head dome and flange (low-alloy steel with stainless steel cladding)

* RV closure studs, nuts, and washers (low-alloy steel)

intermediate and lower shell courses (low-alloy steel with stainless steel cladding)

* primary inlet and outlet nozzles and nozzle support pads (low-alloy steel with stainless

steel cladding)

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* refueling seal ledge (carbon steel)

* vessel flange (low-alloy steel with stainless steel cladding)

* upper (nozzle) shell course (low-alloy steel with stainless steel cladding)

* ventilation shroud support ring (carbon steel)

The applicant credits the Borated Water Leakage Assessment and Evaluation Program with the

management of loss of material in these low-alloy steel or carbon steel components.

Identification of Aging Effects

The applicant identified that loss of material is an applicable aging effect for the low-alloy steel

and carbon steel RV components that are exposed to the'inside environment, and it credited

the Borated Water Leakage Assessment and Evaluation Program with management of this

-aging effect. -Th6 appli ant did not identify Which aging mechanisms could lead to the loss of

material in the RV comp6nents that are fabricated from low-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. 'Low-alloy steel and carbon steel components may

also be susceptible to general corrosion in atmospheric environments if the atmospheres are

damp, moist, or humid.

The applicant described the inside environm6nt in Section 3.0.4 and Table 3.0.4-2 of the FNP'

LRA. In the table, the applicant provided the'following definition for the inside'environment:

'The environment [is] found within environmentally controlled structures. As a minimum,

temperature is controlled to prevent freezing. This environment includes the Containment

Building, Auxiliary Building, EDG Building, and Service Water Intake Structure.

Within containment, the average bulk temperature is 120 "F, with 5O/a-95% humidity, and up to - 1 RAD per hour dose rates. The'air temperature varies throughout the Containment according to

location and elevation. Some areas of the containment (e.g., hot pipe penetrations) may be -subject to elevated localized temperatures.

Components located in the area of systemscontaining borated water may be subject to borated

'water leakage. '- ' -

The description of the inside environment in the FNP LRA did not indicate if the applicant

managed the water vapor content in the inside environment to low humidity levels. Therefore,

the staff asked the'applicant to clarify whether the loss of material due to general corrosion was

an applicable aging effect for external surfaces of .low-alloy steel or carbon steel RVcomponents that are exposed to the-inside'environment and, if not, to justify the exclusion ofgeneral corrosion from management during the period of extended operation. The staff

identified this issue as RAI 3.1 ;3.1.2-1 ,Part a, and informed the applicant that the scope of the

RAI ap'plied to the following RV components: - ;-

* bottom head torus and dome (low-alloy steel with stainless steel cladding)

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* closure head dome and flange (low-alloy steel with stainless steel cladding)

* RV closure studs, nuts, and washers (low-alloy steel)

* intermediate and lower shell courses (low-alloy steel with stainless steel cladding)

* primary inlet and outlet nozzles and nozzle support pads (low-alloy steel with stainless

steel cladding)

* refueling seal ledge (carbon steel)

* RV flange (low-alloy steel with stainless steel cladding)

* upper (nozzle) shell course (low-alloy steel with stainless steel cladding)

* ventilation shroud support ring (carbon steel)

As discussed in Section 3.0.3.1 of this SER, industry experience has demonstrated that the loss

of material due to boric acid corrosion and boric acid-induced wastage may occur on the.

external surfaces of ASME Code, Class1, low-alloy steel and carbon steel components as a

result of exposure to potential leaks to the reactor coolant (i.e., leaks of the borated water).

Based on this analysis, the staff concludes that the applicant's assertion that the loss of

material due to boric acid corrosion applies to the external surfaces of the low-alloy steel and

carbon steel RV components is acceptable.

The applicant provided its response to RAI 3.1.3.1.2-1, Part a, in SNC Letter No. NL-04-0617,

dated April 16, 2004. In this response, the applicant confirmed that it identified the loss of

material due to boric acid corrosion as an applicable aging effect for the surfaces of carbon

steel or low-alloy steel RV components that are exposed to the inside air environments and

could potentially be exposed to leakage of the borated reactor coolant. This is consistent with

the corresponding AMRs in GALL, Volume 2; therefore, this reasoning is acceptable.

The applicant also stated that it did not consider the loss of material due to general corrosion to

be an applicable aging effect for these components in the inside environment because the

continued presence of moisture is required to sustain significant general corrosion of carbon

steel and low-alloy steel components. Instead, these components operate at temperatures well

above 212 "F. The applicant clarified that since the exterior surface temperatures of the

components significantly exceed the ambient temperature, condensation is not expected to

occur on the external surfaces, and the high surface temperatures would evaporate any -.

moisture or leakage. The staff concurs that this is an acceptable basis for concluding that

general corrosion is not a concern because the operating temperatures for the components

should preclude the occurrence of any precipitation that might otherwise induce general

corrosion in the components. Therefore, RAI 3.1.3.1.2-1, Part a, is resolved.

The applicant indicated that the RV closure studs, nuts, and washers are the only carbon steel

or low-alloy steel RV components in the inside environment that could potentially be subject to

loss of material as a result of wear. This conclusion is consistent with GALL Volume 2, Section

IV.A2. The corresponding AMR in GALL, Volume 2, is commodity group entry IV.A2.1-d.

Based on this assessment, the staff concludes that the applicant's evaluation of wear in the

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carbon steel and low-alloy steel RV components is acceptable because it is consistent with

those AMR commodity groups in GALL that identify wear as an applicable effect for carbon

steel or alloy steel RV components in air-bas6d environments. '

Aging Management Programs

The applicant credited the Borated Water Leaka-ge Assessment and Evaluation Program with

the management of the loss of material frbom the external surfaces of the low-alloy steel or

carbon steel RV components that are exposed to the inside environment. Crediting this AMP

for agingrnanagement implies that 16ss'of material is possible'only from the external surfaces

of low-alloy steel and carbon steel RV cripo-nehts' if through-wall leakage of the berated

coolant occurs in the components. In RAI 3.1.3.1.2-1, Part a, the staff requested additional

information regarding the aging mechanisms that could induce the loss of material from the

external surfaces of low-alloy steel and carbon 'steel RV, RCS piping, and pressurizer.'.- ;

components under exposure to insid eenvironmrents.. Thestaff therefore asked the applicant to

provide its technical basis for concluding that only the Borated Water Leakage Assessment and

Evaluation Programr will be necessary to mana e the loss of material in external surf aces of

low-alloy steel and carbon steel RV corriponie'its, particularly if aging mechanisms other than.;

the boric acid-leakage and boric acid-induced waste are known to induce the-loss of material

aging effect. The staff identified this issue as RAI'3.1.3.1.2-1, Part b, and informed the*

applicant that this RAI also applied to the bvalkationrof the loss of material from the external

surfaces of low-alloy steel or carbon steel RCS piping or pressurizer components.

In its review of the applicant's response to Part a of RAI 3.1.3.1.2-1, dated April 16, 2004, the

staff concurred with the applicant that the loss of material due to general corrosion was not an'

AERM for the external surfaces of ASME Code, Class 1, carbon steel or low-alloy steel RV

components because of the high operating temperatures of the components and the conclusion

that precipitationhon the' external surfaces was unlikely. In its 'response to Part b of RAI -

3.1.3.1.2, dated April 16, 2004, the applicant indicated that an-AMP is not necessary for

managing general corrosion in these components because general corrosion is not identified as

an applicable aging effect for the components. Based on the staff's review of the applicant's

response to RAI 3.1.3.1.2-1, Part a, and concurrence that general corrosion is nrot an aging

effect of concern for the external surfaces of carbon steel/low-alloy steel RV components, the

staff agrees that an AMP is not necessary to manage general corrosion in the external surfaces

of carbon steel or low-alloy steel RV components. Therefore, RAI 3.1.3.1.2, Part b, is resolved.

As discussed in Sections 3.0.3.1'and 3.0.3.1.1 of this SER, industry experience has

demonstrated that the loss of material due to boric acid leakage and boric acid-induced

wastage (i.e., boric acid-induced corrosion) i'ay'occur on the external surfaces of ASME Code,

Class 1, low"alloy steelr'aid carbon steel `6riipo i hts that could potentially be xposed to leaks

to the reactor coolant'(i.e., leaks of the borated water). The staff issued GL 88-05 to address

the impacts of this issue on'the PWR industry. Based on this operating experience, Section IV

of GALL, Volume 2, identifies that loss of material due to boric acid corrosion is an AERM for

external surfaces of carbon steel and low-alloy steel components. The staff concludes that

crediting the Borated Water Leakage'Assesmeht and Evaluation Programi with the

management of the loss of material 'due to boric acid leakage and wastage for the surfaces of

low-alloy steel or carbon steel RV components that ar6 exposed to the inside environment is -

acceptable because it is consistent with GALL, Volume 2,' and industry experience. 'Sections

3.0.3.1 and 3.0.3.1.1 of this SER provide the staff's evaluation of the Borated Water Leakage

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Assessment and Evaluation Program.

The applicant credited its Inservice Inspection Program with managing the loss of material on

RV closure studs, nuts, and washers as a result of wear. GALL commodity group IV.A2.1-d

recommends use of a bolting integrity program for the management of wear in these closure

stud assembly components. Instead, the applicant uses the bolting requirements of ASME

Code, Section Xl; Inspection Category B-G-1. as the basis for examining these once every

inspection interval. This inspection category is invoked by the requirements of 10 CFR 50.55a.

The staff finds this to be an acceptable alternative to a bolting integrity program because the

inspections will be done in accordance with applicable NRC ISI requirements for the RV closure

stud assembly components. The staff evaluates the Inservice Inspection Program in Section

3.0.3.1 of this SER.

The staff has reviewed the applicant's AMRs for evaluating loss of material in Class 1 RV

components that are made from carbon steel or low-alloy steel materials and that are exposed

to the inside environment.- The staff concludes that the applicant has provided an acceptable

technical basis for concluding that the loss of material due to general corrosion is not an

applicable AERM for the external component surfaces that are exposed to the inside

environment. The staff also concludes that the applicant has credited an acceptable AMP for

managing the loss of material from the external surfaces of carbon steel or low-alloy steel RV

components that could be potentially exposed to borated reactor coolant. The staff concludes

that the applicant has also credited an acceptable inspection-based AMP to manage loss of

material in the RV closure studs, nuts, and washers as a result of wear.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

Aging Effects That Are ApDlicable to NiCrFe or Stainless Steel RV Components That Are

ExDosed Externally to Inside (Atmospheric) Environments

Summary of Technical Information in the Application.

In Table 3.1.2-1 of the LRA, the applicant provided its AMRs for evaluating the effects of aging

that apply to NiCrFe and stainless steel RV components that are exposed externally to the

inside (atmospheric) environment. With the exception of the AMR for evaluating the loss of

material in the CET bolts and the HJTC assembly bolts, the applicant concluded in these AMRs

that exposure of the external surfaces of the NiCrFe and stainless steel RV components to the

inside environment will not result in any aging effects that require management during the

period of extended operation for the FNP units.

In its corresponding AMRs for evaluating aging in the stainless CET bolts and HJTC assembly

bolts, the applicant concluded that cracking and loss of material are both aging effects that

require aging management for the period of extended operation for the FNP units. The

applicant designated these AMRs as note E items in the table.

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The scope of this commodity group assessment includes the following components:

* BMI guide tubes (stainless steel)

* BMI penetrations (Alloy 600)

CET and HJTC assemblies (stainless steel)

* CRDM and instrumentation housing penetration nozzles (thermally treated Alloy 690)

* CRDM housing flange adapters (stainless steel)

* - CRDM latch housings and rod travel housings (stainless steel)

* zRV head vent penetration (thermally treated Alloy 690)

* RV leakage monitoring tube assembly (Alloy 600)

* RV primary nozzle safe end (stainless steel with Alloy 82/182 welds and buttering)

* seal table and fittings (stainless steel)

Identification of Aging Effects

In Section 3.1.2.1 of this SER, the staff evaluated the applicant's AMRs for aging effects in the

CET bolts and HJTC assembly bolts under exposure to the inside environment.

With the exception of the applicant's AMRs for evaluating aging that may apply to the stainless

steel CET bolts and stainless steel HJTC assembly bolts, the applicant concluded that there are

no aging effects that require aging management for the external of NiCrFe and stainless steel

RV components that are exposed externally to the inside environment. Nonbolted ASME Code,

Class 1, NiCrFe and stainless steel materials are designed to resist corrosi6n-based'

mechanisms that may induce corrosion-induced cracking or loss of material under exposure to

moist, damp, or wet air environments. The staff therefore concurs that, with the exception-of

the management of cracking and loss of material that may occur in the CET bolts and HJTC

bolts under exposure to the inside environment, loss of material and cracking are 'hot aging

effects that require management for the surfaces of nonbolted NiCrFe and stainless ASME

Code Class 1 components that are exposed to the inside environment.

In Table 3.1.2-1 of the LRA, the applicant concluded that cracking and loss' of material are both

aging effects that require management for the CET bolts and HJTC assembly bolts under

exposure to the inside environment. Section 3.1.2.1 of this SER provides the staff's evaluation

of the applicant's AMRs for aging effects in the CET bolts and HJTC assembly bolts' under

:exposure to the inside environment. ;

Aging Management Programs

The applicant did not credit any AMPs for the management of the loss of material ordcracking in

the surfaces of nonbolted ASME Code, Class 1, NiCrFe and stainless steel components under

exposure to the inside environment 'Since'these components are designed to resist corrosion

under exposure to air environments, the staff concurs that aging management isn'not necessary

for the surfaces of these components that are exposed to the inside environment.

In Table 3.1.2-1 of the LRA, the applicant credited the Inservice Inspectioni Program for the

management of cracking and loss of material that may occur in the CET bolts and HJTC - assembly bolts under exposure to the inside environment. Section 3.1.2.1 of this SER provides

the staff's evaluation of the ability of the Inservice lnrisection Program to manage the loss of

material and cracking in the CET bolts and HJTC assembly bolts.

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The staff has reviewed the applicant's AMRs for evaluating whether loss of material is an AERM

for the surfaces of nonbolted ASME Code, Class 1, NiCrFe and stainless steel components

under exposure to the inside environment. The staff has determined that the applicant provided

an acceptable basis for concluding that loss of material is not an AERM for the external

surfaces of nonbolted ASME Code, Class 1, NiCrFe and stainless steel components that are

exposed to the inside environment.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects that result from contact of the

reactor vessel, internals, and RCS SSCs with the environments described in Tables 3.1.2-1

through 3.1.2-4 of the LRA are consistent with industry experience for these materialenvironment combinations. Therefore, the staff finds that the applicant identified the applicable

aging effects that are appropriate for the material-environment combinations listed.\

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.1.2.3.2 Reactor Vessel Internals Aging Management Review Results

3.1.2.3.2.1 Summary of Technical Information in the Application

In Section 3.1.2.1.2 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs that handle the AERMs for the reactor

vessel internals components:

* Water Chemistry Control Program

* Inservice Inspection Program

* Reactor Vessel Internals Program

* Flux Detector Thimble Inspection Program

In Table 3.1.2-2 of the LRA, the applicant summarized the AMRs for the reactor vessel internals

components and identified which AMRs it considered to be consistent with the GALL Report.

3.1.2.3.2.2 Staff Evaluation

Loss of Material in Austenitic Stainless Steel or Nickel-Based Alloy RV Internal Components

Under Exposure to the Borated Water Environment

Summary of Technical Information in the Application

The applicant identified that loss of material is an AERM for nickel-based (NiCrFe) alloy and

austenitic stainless steel RV internal components that are exposed to borated water

environments. In Table 3.1.2-2 of the LRA, the applicant designated these AMRs as note H

items. The scope of this commodity group includes the following components:

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* baffle/former plates (stainless steel)

* baffle bolts (stainless steel)

* BMI column cruciforms (CASS)

* BMI columns with associated fasteners (stainless steel)

* clevis inserts and fasteners (NiCrFe alloys-Alloy 600 for the inserts and Alloy X-750 for

the fasteners)'

* control rod guide'tube (CRGT) assemblies with associated fasteners (stainless steel) - ,,~~ , . . .... -;!.,.....- A *_- 

* core barrel and core barrel flange (stainless steel)

* - core barrel outlet nozzles (stainless steel)

* ' ' 'CRGT support pins (stainless steel) -

* -'flux thimble tubes (stainless steel) ,' -

* head/RV alignment pins'with associated fasteners (stainless steel) -

* head cooling spray nozzles (stainless steel)

* *HJTC probe holder, probe holder extension, and probe holder shroud assemblies with

associated fasteners (stainless steel)

* internals holddown spring (stainless steel)

* lower core plate and fuel alignment pins with associated fasteners (stainless steel)

* 'lower support columns with associated fasteners (stainless steel)

* lower support forging (stainless steel)

* neutron panels with associated fasteners (stainless steel)

* radial support keys and fasteners (stainless steel)

* secondary core support assembly with associated fasteners (stainless steel)

* upper core plate alignment pins with associated fasteners (stainless steel)

* upper core plate and the fuel alignment pins with associated fasteners (stainless steel)

* upper instrumentation conduit and supports with associated fasteners (stainless steel)

* upper support assembly'with associated fasteners (stainless steel) -

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- a

upper support column bases (CASS)

* upper support columns with associated fasteners (stainless steel)

Identification of Aging Effects

The applicant identified that loss of material is an applicable aging effect for NiCrFe

components and stainless steel RV internal components that are exposed to borated water

environments. It categorized its AMR for these components as one for which the GALL Report

did not identify an aging effect for the material-environment combinations for the components

(i.e., note H designation in Table 3.1.2-2). These components include CASS RV internal

components that are exposed to the borated water environments.

The applicant did not identify in Section 3.1 of the LRA or in LRA Table 3.1-2-1 which aging

mechanisms could lead to the loss of material in these commodity group components. In SER

Section 3.1.3.1.1, the staff evaluated the validity of applicant's identification of the aging

mechanisms that could induce a loss of material in NiCrFe and stainless steel RV components.

In RAI 3.1.3.1.1-1, Part a, the staff requested that the applicant identify all aging mechanisms

that could lead to the loss of material in NiCrFe and stainless steel RV, RV internal, RCS piping,

and pressurizer components that are exposed to borated water. The staff identified the

following NiCrFe and stainless steel RV internal components as within the scope of RAI

3.1.3.1.1-1, Part a:

* baffle/former plates (stainless steel)

* baffle bolts (stainless steel)

* BMI column cruciforms (CASS)

* BMI columns with fasteners (stainless steel)

* clevis inserts and fasteners (NiCrFe alloy-Alloy 600 inserts and Alloy X-750 fasteners)

* CRGT assemblies with associated fasteners (stainless steel)

* core barrel and core barrel flange (stainless steel)

* core barrel outlet nozzles (stainless steel)

* CRGT support pins (stainless steel)

* flux thimble tubes (stainless steel)

* RPV/head alignment pins with associated fasteners (stainless steel)

* head cooling spray nozzles (stainless steel)

* HJTC probe holder, probe holder extension, and probe holder shroud assemblies with

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' associated fasteners (stainless steel)

* internals holddown spring (stainless'steel)"

* lower core plate and fuel alignment pins' (stainless steel)

* lower support' columns with associated fasteners (stainless steel)

* lower support forging (stainless steel)' -

* neutron panels (stainless steel)'

' radial keys and fasteners (stainless steel)

* secondary core support assembly with'asso6iated fasteners (stainless steel)

* upper core alignment pins with associated fasteners (stainless steel)

* upper core plate and fuel alignment pifis'with'associated fasteners (stainless steel)

*' upper instrumentation 'onduit and supports with associated fasteners (stainless steel)

*-' - upper support assembly with associated fasteners (stainless steel)

upper support column bases (stainless 'steel)

* upper support cOlumn with associated fasteners (stainless steel)

The applicant provided its response to RAI 3.1.3.1.1-1, Part a, in SNC Letter No. NL-04-0617,

'dated 'April 16, 2004. In its response to the RAI,'the'applicant confirmed that loss of material

was an'applicable aging effect for all the stainless steel and NiCrFe RV internal components

identified in RAI 31.3.1.1-1, Part a, and that for all of these components, the loss of material

due to crevice corrosion or pitting corrosion was an applicable aging effect/mechanism

requiring management. The applicant also confirmed that it conservatively'assumed that the

loss of material due to wear was an'applicable aging'effect/mechanism requiring management

for the RV internals upper core plate aligriiientjOins, holddown spring,-clevis inserts and

fasteners, radial support keys and fasteners,`and flux detector thimble tubes.'

The staff concludes that the applicant's response to RAI 3.1.3.1.1-1, Part a, is acceptable

because it clarifies which aging mechanisms could induce a loss of rriaterial for the stainless

steel or NiCrFe RV internal components that LRA Table 3.1.2-2 identified as exposed to

b6irted water. Therefore,' RAI 3.1.3.1.1 1,;Part a, is res'olved. 'Section 3.1.2.3.3, in the

subsection'entitledi"Aging Management-Programs'or Activities Credited with'Aging.

Management," provides the staff's assessment of the AMPs credited for managing loss of--<

material in'these components. :

Aging Management Programs

With the ex6eption of AMRs in LRA Table 3.1.2-2 for managing the loss of rmaterial in the in3-121
I

core flux thimble tubes, internals holddown spring, cleVis inserts and fasteners, upper core plate

alignment pins, and the radial support keys and fasteners, the applicant credited the Water

Chemistry Control Program as the AMP for managing the loss of material that may occur in the

NiCrFe and stainless steel RV internal components (including RV internal components

fabricated from CASS) that are exposed to the borated water environment.

As described under "Aging Management Programs or Activities Credited with Aging

Management," the staff requested in RAI 3.1.3.1.1-1, Part b, that the applicant provide its

technical bases for considering only the Water Chemistry Control Program to be sufficient to

manage the loss of material in NiCrFe and stainless steel (including CASS) RV internal

components without including an inspection-based AMP to confirm that the Water Chemistry

Control Program is accomplishing its mitigative function. As an alternative, the staff asked the

applicant to propose an acceptable inspection-based AMP for the management of the loss of.

material in the specific NiCrFe or stainless steel RV components. The staff identified that RAI

3.1.3.1.1-1, Part b, also applied to the staff's evaluation of the applicant's AMPs credited with.

managing the loss of material in NiCrFe, stainless steel, and CASS RV internal components.

As discussed in Section 3.1.2.3.1.2 of this SER, under the subsection 'Aging Management

Programs," the applicant's response to RAI 3.1.3.1.1-1, Part b, provided an acceptable

explanation for using the Water Chemistry Control Programi as a basis for minimizing the

dissolved oxygen and ionic impurity concentrations that could otherwise, if. left present in high

concentrations, lead to an aggressive, oxidizing RCS coolant environment. The GALL Report

does not indicate that the loss of material due to pitting or crevice corrosion is an aging effect of

concern for stainless steel or NiCrFe ASME Code, Class 1, components. Since the applicant

has conservatively assumed that the loss of material due to pitting or, crevice corrosion is an

applicable aging effect for all of the RV internal components identified as fabricated from

stainless steel or NiCrFe materials, the staff concludes that the Water Chemistry Control

Program provides a sufficient mitigative strategy for managing this aging effect relative to the

recommendations of the GALL Report. Therefore, RAI 3.1.3.1.2-1, Part b, is resolved with

respect to the AMPs that are credited for managing the loss of material in the stainless steel or

NiCrFe RV internals components as a result of pitting or crevice corrosion. Section 3.0.3.2.1 of

this SER provides the staff's evaluation of the Water Chemistry Control Program.

In its response to RAI 3.1.3.1.1-1, Part a, the applicant confirmed that the upper core plate

alignment pins, holddown springs;.clevis inserts and fasteners, radial support keys and

fasteners, and flux detector thimble tubes are the RV internal components that could potentially

be subject to the loss of material due to wear as a result of the exposure of the components to

the borated water environment.

In commodity group IV.B2.1-l of GALL, Volume 2, the staff evaluates the loss of material in

upper core plate alignment pins associated withthe upper internals assembly and recommends

crediting the ASME Code, Section Xl, Inservice Inspection, Subsections IWB, IWC, and IWD

Program for ASME Code Class 1. components with management of the aging effect.- In

commodity group IV.B2.5-o of GALL, Volume 2, the staff evaluates the loss of material in radial

keys and clevis inserts associated with the lower internal assembly and recommends crediting

the ASME Code, Section XI, Inservice Inspection, Subsections IWB, IWC, and IWD Program

with management of this aging effect.

The current ASME Code, Section XI, ISI requirement for inspection of nonwelded RV internals

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is that'specified in Table IWB-2500-1, InspectionrCategory B-N-1, Inspection Item B13.10. This

ASME'inspection item requires that U.S. nuclear licensees perform 'visual VT-3 inspections of

the accessible areas internal to the reactor vessel once every inspection period.

The applicant determined that its AMR for rmanaging the loss -of material in the upper core plate

alignment pins associated with the FNP upper riternals assemblies was consistent with the

AMR in GALL commodity group IV.B2.1a-. The applicant decided that'its AMR for managing the

loss of material in the radial keys and clevis in'serts-associated with the FNP lower internal

assemblies was consistent with the correspondihg AMR in GALL commodity group IV.B2.5-o.

At FNP, these components are fabricated from stainless steel. Based 'on these determinations,

the applicant credited the Inservice Inspection'Program'with the management of the loss of

material in these components. In Section 3.1.2.1 of this SER, the staff evaluated the -

applicant's crediting of the Inservice Inspection Program for management of the loss of material

in these components and determined that'it'was acceptable.

The applicant has also identified that loss'6f'material is'an applicable aging effect for the RV'

internals holddown springs, which at FNP are fabricated from stainless steel.- Section IV.B of:

GALL, Volume 2, does not include'a correspon6ding AMR commodity group for evaluating loss

of material in RV internals holdddwn sprii'gs.- The'applicant credited both the Inservice

Inspection Program and the Water Chemistry Control Program with the management of theloss of material in the RV internals holddovn springs. '

The applicant's AMPs for managing the loss of material in the RV internals holddown springs

are identical to those credited for managing the lss' of rmaterial due to wear in the radial - . -

support keys and fasteners and the upper core piate6alignment pins; They are therefore based

on the same ASME Code VT-3 inspection strategies and water chemistry control practices

proposed for managing the aging effects in the radial'support keys and fasteners and the upper

core' plate aligriment pins. Because the functions, materials, and environments for the RV

internals holdd6wn springs are similar to'those for the'radial support keys and fasteners and

upper'core plate alignment pins, the staff coibludes that the Inservice Inspection 'Program and

Water Chemistry Control Program are acceptable&s for managing the loss of material in

the RV internals holddown springs.

Based on'this assessment, the staff corcludes the Inservice Inspection Program and Water

Chemistry Control Program are acceptable AMPs for managing the loss of material in the RV.

internals upper core plate align'ment pins,' hblddown springs,; clevis inserts and fasteners, and

radial support keys and fasteners. S6ctions 3.0.3.1 'and 3.0.3.2.1 of this SER provides the

staff's evaluation of the Inservice Inspection Program and Water Chemistry Control Program,

respectively. - . . , '

For managing the loss of mnaterial in the in-core flux detector thimble tubes, the applicant

credited both the Flux Detector Thimble Irspection Program and the WaternChemistry Control

Program. Thie AMR for commodity group IV.B2.6-c' of GALL, Volume 2, recommends using the

following two AMPs for the management of the loss'of material due to Wear in in-core flux,.--..,

thirnbl e's (tubeis) ' >:'-

(1) ASME Code, Section Xl, Inservice'' Inspection, Subsections IWB, IWC, and IWD

Program for ASME Code 'Class 1'Icomponents

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(2) a plant-specific inspection program designed to address the technical issues and criteria

of NRC Bulletin 88-09, "Thimble Tube Thinning in Westinghouse Reactors," issued

July 26, 1988 f

The applicant's decision to credit the Flux Detector Thimble Inspection Program for managing

the loss of material due to wear in the flux detector thimble tubes is consistent with commodity

group IV.B2.6-c of GALL,,Volume 2, and with the staff's position that a plant-specific inspection

program should be credited for the management of wear in flux detector thimble tubes.

Therefore, the applicant's crediting of the Flux Detector Thimble Inspection Program for aging

management is acceptable to the staff. The staff evaluates the ability of the Flux Detector

Thimble Inspection Program to manage wear in the FNP flux detector thimble tubes in Section

3.0.3.3.1 of this SER.

Commodity group IV.B2.6-c of GALL, Volume 2, also recommends crediting the ASME Code,

Section Xl, Inservice Inspection, Subsections IWB, IWC, and IWD Program for ASME Code

Class- 1 components with managing the loss of material due to wear in the flux detector

thimbles. Inspection Categories B-N-1 and B-P of Table IWB-2500-1 in ASME Code,

Section Xl, apply to these components. The applicant did not credit the Inservice Inspection

Program for management of the loss of material due to wear. in the flux detector thimble tubes

at FNP. The staff requested the applicant to provide its basis for not crediting the Inservice

Inspection Program with aging management of the loss of material due to wear in the flux

detector thimble tubes. The staff identified this issue as RAI 3.1.3.2.1-1.

The applicant provided its response to RAI 3.1.3.2.1-1 in SNC Letter No. NL-04-0617, dated

April 16, 2004. In its response to RAI 3.1.3.2.1-1, the applicant stated that the nominal

pipe/tube size of the FNP flux detector thimble tubes is less than 1.0 inch in diameter and that

ASME Code, Section Xl, exempts small-bore piping from the volumetric and surface

examination requirements of IWB-2500. The staff has confimied that paragraph IWB-1220 of

ASME Code, Section Xl, exempts pipes/tubes with nominal sizes less than 1.0 inch in diameter

from volumetric and surface examinations. The staff therefore concludes that the applicant has

provided an acceptable basis for not crediting the ASME Code, Section Xl, volumetric

examination and surface examination requirements for the flux detector thimble tubes.

Inspection Category B-N-1, Inspection Item B13.10, of ASME Code, Section Xl, requires the

performance of visual VT-3 examinations on the interior of the reactor vessel once every

refueling outage. The Flux Detector Thimble Inspection Program uses ECT to monitor for wear

in the flux detector thimble tubes, which is a volumetric inspection method for thin-walled tubing,

such as flux detector thimble tubing or SG tubing. Industry experience has demonstrated that

ECT examinations performed on Westinghouse-designed flux detector thimble tubes can detect

wear-induced loss of material in these components and that ECT is a conservative method for

implementing the VT-3 examinations required by ASME Code, Section Xl. Since the ECT

examinations are sufficient by; themselves to monitor for wear in the flux detector thimble tubes,

the staff concurs that the applicant need not credit the VT-3 examinations required by the

ASME Code, Section Xl, for the flux detector thimble tubes. However, although the applicant

will not credit ASME Code, Section Xl, Inspection Category B-N-1, Inspection Item B1 3.10, for

the FNP LRA, it must still perform the required VT-3 examinations of the FNP RV interior during

each refueling outage for the period of extended operation for the FNP units, unless the

applicant requests and receives appropriate relief from the staff, pursuant to the provisions of

10 CFR 50.55a(a)(3). Based on this evaluation, the staff concludes that the applicant has

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provided an acceptable basis for handling the loss of material due to.wear in the flux detector

thimble tubes without the need to credit the Inservice Inspection Program for aging

management. Therefore, RAI 3.1.3.2.1-1 is resolved.

The staff has reviewed the applicant's-AMRs for-evaluating the loss of material in ASME, Code

Class 1, RV internal components that are made from stainless steel or NiCrFe materials-and

are exposed to borated water. The staff concludes that the applicant has credited an

acceptable basis for concluding that the Water Chemistry Program is sufficient to manage the

loss of material in these components as aresult of pitting or crevice corrosion. The staff also

concludes that the applicant has credited acceptable inspection-based AMPs to manage the

loss of material in the RV internals upper core plate alignment pins, holddown springs,-clevis

inserts and fasteners, radial support keys and fasteners, and flux detector thimble tubes as a

result of wear.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects that result fromr contact of the

reactor vessel, internals, and RCS SSCs with the environments described in Tables 3.1.2-1

through 3.1.2-4 of the LRA are consistent with industry experience for these materialenvironment combinations. Therefore, the staff finds that the applicant identified the applicable

aging effects that are appropriate for the material-environment combinations listed.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).-

3.1.2.3.3 Reactor Coolant System and Connected Lines Aging Management Review Results

Summary of Technical Information in the Application -

Table 3.1.2-3 of the LRA provides the applicant's specific AMRs for components that comprise

the FNP reactor vessel coolant system. These components include the reactor coolant piping,

system piping, pressurizer, and components. This SER evaluates the applicant's identification

of aging mechanisms and AMPs for items designated as letters F through J in the subject table.

Loss of Material in Austenitic Stainless Steel or Nickel-Based Alloy RCS PiPing and Fitting

Components Under Exposure to the Borated Water Environment

Summary of Technical Information in the Application

The applicant identified that loss of material is an applicable aging effect for NiCrFe

components and stainless steel RCS piping and fitting components that are exposed to borated

water environments.- It categorized its AMR for these components as one for which the GALL.

Report did n6t idehtify an aging effect for the material-environmental combinations for the

componients (i.e., notes H and J in Table 3;1.2-3). The scope of this commodity group includes

the following components:

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* Class 1 piping-reactor coolant loop (CASS)

* small-bore Class 1 piping less than NPS 4 (stainless steel)

* Class 1 piping greater than or equal to NPS 4 (stainless steel)

* Class 1 valve bodies (stainless steel)

* Class 1 flow orifices or elements (stainless steel)

* RCP casing (CASS)

* RCP main closure flange (CASS)

* pressurizer heater sheaths (austenitic stainless steel)

* pressurizer instrumentation nozzle and heater well nozzles (stainless steel)

* pressurizer manway and cover (alloy steel with stainless steel insert)

* pressurizer nozzle safe ends (stainless steel with Alloy 82/182 welds and buttering,

NiCrFe weld filler metals)

* pressurizer surge, spray, safety, and relief nozzles (alloy steel with stainless steel

cladding)

* pressurizer shell, upper head, and lower head (alloy steel with stainless steel claddin g)

* pressurizer spray head assembly (CASS)

* pressurizer surge and spray nozzle thermal sleeves (stainless steel with Alloy 82/182

welds, NiCrFe weld filler metals)

* non-Class 1 RCS piping (stainless steel)

* non-Class 1 valve bodies (stainless steel)

* RCP thermal barrier assembly

The applicant credited the Water Chemistry Program and the One-Time Inspection Program

with the management of the loss of material in these components.

Identification of Aging Effects

The applicant identified the loss of material as an applicable aging effect for NiCrFe

components and stainless steel RCS piping and fitting components that are exposed to borated

water environments. These components include carbon steel or low-alloy steel components

that are clad with austenitic stainless steel that is exposed to the borated water environments.

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It
I

The applicant did not identify in Section 3.1 of the LRA or in LRA Table 3.1.2-3 which aging

mechanisms it considered capable of inducing a loss of material in the stainless steel (including

stainless stel 'clad components) or NiCrFe RCS piping and fitting components exposed to

borated water. The'staff required additional information on this matter._,Specifically, for each of

these components, the staff requested that the applicant define the aging mechanisms it

considered able to induce a loss of material in the components. The staff identified this issue

as RAI 3.1.3.1.1-1, Part a.: The staff also'informed the applicant that this RAI applied to

comparable NiCrFe and stainless steel RV internals components within the scope of Table

3.1.2-2 and comparable NiCrFe and stainless steel RV components within the scope of Table

3.1.2-1. Part a of RAI 3.1.3.1.1-1 applies to the following RCS piping and fitting components:

* Class 1 piping-reactor coolant loop (CASS)

* small-bore Class 1 piping less than NPS 4 (stainless steel) ; :. .; ,,.................... ,.,..,- - -. . . . . . . . ..... '........

* Class 1 pipirig greater than or equal to NPS-4 (stainless steel)

* Class 1 valve bodies (stainless steel).,

* Class 1 flow orifices or elements (stainless steel)

*' RCP casing (CASS)

* RCP main closure flange-(CASS) -

* ' pressurizer heater sheaths (austenitic stainless steel)

* pressurizer instrumentation nozzle'and heater well nozzles (stainless steel)

* pressurizer manway and cover (alloy steel with stainless steel insert)

* pressurizer nozzle safe ends (stainless steel with Alloy 82/182 welds and buttering,

-NiCrFe weld filler metals)

* pressurizer surge, spray, safety, and relief nozzles (alloy steel with stainless steel

cladding)' - ' '''' 'C.

* pressurizer shell, upper head, and lower head (alloy steel with stainless steel cladding)

* pressurizer spray head assembly (CASS)

* -'pressurizer surge and spray nozzle thermal sleeves (stainless steel with Alloy 82/182

welds, NiCrFe weld filler metals) :- - .-. - -.

* non-Class 1 RCS piping (stainless steel) -

* non-Class 1 valve bodies (stainless steel)

* RCP thermal barrier.assembly.

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Section 3.1.2.3.1.2 of this SER discusses the staff's review of the applicant's response to RAI

3.1.3.1.1-1, Part a, regarding the aging mechanisms that can lead to the loss of material in the

NiCrFe and stainless steel RCS piping and fitting components listed in LRA Tables 3.1.2-1,

3.1.2-2, and 3.1.2-3 under exposure to the borated water environment.

Aging Management Programs or Activities Credited with Aging Management

The applicant has credited the Water Chemistry Program and the One-Time Inspection

Program for the management of the loss of material that may occur in the NiCrFe and stainless

steel RCS piping and fitting components that are exposed to the borated water environment.

Pitting and crevice corrosion may occur in ASME Code, Class 1, stainless steel or NiCrFe

piping components under exposure to aggressive, oxidizing environments. Normally, the

presence of elevated dissolved oxygen and/or aggressive ionic impurity concentrations is

necessary to create these oxidizing environments in the RCS. In RAI 3.1.3.1.1-1, Part a, the

staff inquired whether loss of material due to either wear or erosion was an applicable aging for

ASME Code Class 1 pressurizer or RCS piping and fitting components that are made from

either stainless steel (including CASS) or NiCrFe materials. In the applicant's response to RAI

3.1.3.1.1-1, Part a, the applicant did not identify that stainless steel (including CASS) or NiCrFe

components in the pressurizer or RCS piping systems could be impacted by loss of material

due to wear. The applicant did conservatively identify that loss of material due pitting or crevice

corrosion is an applicable aging effect for stainless steel or NiCrFe components in the

pressurizer or RCS piping systems and fitting components. -In the evaluation in Section

3.1.2.3.1.2 of this SER, the staff evaluated and justifies why the Water Chemistry Control

Program is sufficient to manage pitting and crevice corrosion in stainless steel/NiCrFe ASME

Code Class 1 components, including ASME Code Class 1 pressurizer and RCS piping and

fitting components made from stainless steel or NiCrFe materials.

The applicant credited both the One-Time Inspection Program and the Water Chemistry Control

Program with the management of the loss of material from the pressurizer spray head

assembly, a CASS component. Commodity group IV.C.2.5.4 of GALL, Volume 2, lists the

aging effect of cumulative fatigue damage/fatigue as an applicable aging effect for CASS, to be

supported by a TLAA for the pressurizer spray head. Table 3.1.1, Item 3.1.1-12, omits this

aging effect (cumulative fatigue damage), although the applicant listed the material for the

pressurizer spray head assembly as CASS. Section 4.3 of this SER discusses the staff's

evaluation of the credit given by the applicant to the TLAA for the RCPB. Section B.5.5 of this

SER evaluates the One-Time Inspection Program. The staff required further information

regarding whether the applicant manages fatigue aging effect of cracking due to cumulative

fatigue in the CASS pressurizer spray head assembly through the TLAA. Therefore, RAI

3.1.3.3-1 stated that Tables 3.1.1 and 3.1.2-3 do not list the CASS pressurizer spray head

assembly as susceptible to cracking due to thermal fatigue, nor do they indicate that a TLAA

exists to address aging management for this component. For this component and commodity

group (IV.C.2.5.4), GALL recommends a TLAA to address cumulative fatigue damage. The

staff asked the applicant to provide further information regarding whether this plant-specific

component is susceptible to the AERM.

In its response to RAI 3.1.3.3-1, the applicant stated that, for FNP, SNC normally manages

cracking due to thermal fatigue through a TLAA or through the Fatigue Monitoring Program.

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Il
However, the spray head assemibly is not a part of the pressure-retaining boundary, as defined

by the ASME Code. 'Accordindiy,'SNC does not have'fatigue calcuilations associated with this

assembly and no corresponding cumulative fatigue usage factor prediction to maintain for this

assembly. Theref6re, the applicant'stated that it has no TLAA to address cumulative fatigue

damage for the pressurizer spray head assembly.'

The applicant noted that, although it has no TLAA for the spray head assembly, the

corresponding pressurizer nozzle forms part of the pressure-retaining boundary and therefore

has a fatigue calculation. The applicant manages cracking due to thermal fatigue for this spray

nozzle through a TLAA and the Fatigue Monitoring Program. The spray nozzle thermal -

transient cycles correlate to those experienced by the'spray head assembly. The management

of thermal fatigue for'the spray nozzle confirms, for both the spray nozzle and the spray head

assembly, that the fatigue cycles experienced remain within the original design parameters.

The appiicant's description of the physical configuration and operating parameters for the FNP

spray heads minimizes the potential for-cracking due to thermal fatigue cycling. The FNP

CASS spray head is threaded onto a stainless steel coupling, which is welded to the

pressurizer's hemispherically shaped'upper head.; A stainless steel locking bar that is tack

welded to the spray head on one end, and the pressurizer upper head at the other end,

precludes the loosening of the spray head threaded joint. This configuration does not restrain

thermal movement, with the possible-exception'of the locking bar tack weld areas. No

significant pressure stresses are present,'since the operating pressures on both sides of the

spray head are similar. Finally, FNP operates with a continuous flow of coolant through the'

spray head, thereby significantly reducing the number and magnitude of thermal transients

affecting the spray head assembly. Since thermal movement is not restrained, and low fatigue

-usage is expected, SNC concluded that cracking of the FNP spray head assemblies due to

fatigue cycling is not likely.

Finally, the applicant stated that Table 3.1.2-3 of the LRA identifies cracking as an AERM for

the pressurizer spray head assembly.- The applicant credited a one-time, visual VT-1i

examination of higher stress regions associated with the pressurizer spray head assembly to

identify any cracking, whether induced by SCC or caused by fatigue cycling. -Based on the

applicant's description of the configuration and the operation of the pressurizer spray, head with

continuous spray, the staff concludes that the Fatigue Monitoring Program and the One-Time

Inspection Programr'adequately manage the nozzle configuration aging mechanisms. Section

B.5.7 of this SER evaluates the Fatigue Monitoring Program, and Section B.5.5 of this SER

evaluates the One-Time Inspection Program.' Therefore, the staff considers RAI 3.1.3.3-1 to be

closed.

With the acceptable resolution of RAls 3.1.3.1.1-1, Parts a and b; and B.5.8-1, the .staffconcludes that the applicant's AMRs for evaluating the loss of material in RCS Class 1 piping

and components fabricated from 'Alloy 82/182 welds,'stainless steel, or CASS under internal:-

exposure to the borated water environment' adequately identify and manage the effects of aging

and are, therefore, ac6eptable. The staff haszdetermined that the applicant provided an

acceptable basis for'nmanaging loss of mnaterial in RCS Class 1 piping and fitting components

fabricated fromr Alloy 82/182 welds, stainless steel, and CASS under internal exposure to the

borated water environment.' The staff concludes that the applicant proposed acceptable AMPs

for managing the lo's sof material 'as a'result of crevice corrosion,, and pitting corrosion in the

stainless steel arnd NiCrFe components listed in Table 3.1.2-3.-

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The staff has reviewed the applicant's AMRs for evaluating the loss of material in the ASME

Code RCSs and connected lines listed under Table 3.1.2-3 that are made from stainless steel

or NiCrFe materials and exposed to borated water. The staffconcludes that the applicant has

credited an acceptable basis for concluding that its Water Chemistry Control Program is

sufficient to manage the loss of material in these components as a result of pitting or crevice

corrosion.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

Loss of Material in Low-Alloy steel or Carbon Steel RCS Piping and Fitting Components That

Are Exposed Externally to Inside (Atmospheric) Environments

Summary of Technical Information in the Application

The applicant identified loss of material as an AERM for low-alloy steel and carbon steel

components that are exposed externally to the inside (atmospheric) environment (note H). The

scope of this commodity group includes the following components:

* Class 1 closure bolting (alloy steel)

* RCP main flange bolting (alloy steel)

* pressurizer closure bolting (alloy steel)

* pressurizer manway cover (alloy steel with a stainless steel insert)

* pressurizer nozzles (surge, spray, safety and relief nozzles-low-alloy steel with

stainless steel cladding)

* pressurizer shell, upper head, and lower head (alloy steel with stainless steel cladding)

The applicant credited the Borated Water Leakage Assessment and Evaluation Program with

the management of the loss of material in these components.

Identification of Aging Effects

As discussed in Section 3.0.3.1 of this SER, industry experience has demonstrated that the loss

of material due to boric acid corrosion and boric acid-induced wastage may occur in the

external surfaces of ASME Code, Class 1, alloy steel and carbon steel components as a result

of exposure to potential leaks to the reactor coolant (i.e. leaks of the borated water). Based on

this analysis, the staff concludes that the applicant's identification of the loss of material due to

boric acid corrosion as applicable to the external surfaces of the alloy steel and carbon steel'

RCS piping and fitting components is acceptable. The applicant provided its response to RAI

3.1.3.1.2-1, Part a, in SNC Letter No. NL-04-0617, dated April 16, 2004. In this response, the

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11
applicant confirmed that it identified the loss of material due to boric acid corrosion as an

applicable aging effect for the surfaces' of carbon 'steel or low-alloy steel RCS piping and fitting

components that are' exposed to the inside'air enViro'nments and could potentially be exposed

to leakage of the borated reactor coolant. The'staff finds this consistent with the corresponding

AMRs in GALL, Volume 2, and therefore acceptable.

Aging Managemnent Programs

The applicant credited the Borated Water LeakageAssessment and Evaluation Program with

the rmanagement of the loss of material from the external surfaces of the alloy steel or carbon

steel RCS piping arid fitting comnponents'that are' exposed to the inside environment.. In

crediting this AMP for aging management, the applicant implied that it considers the loss of

material possible only from the exteral surfaces of alloy steel and carbon steel-RCS pipingtand

fitting components if through-wall leakage of the borated coolant occurs in the components.' In

RAI 3.1.3.1.2-1, Part a, the staff requested additional information regarding the aging

mechanisms that could induce the loss of material from the external surfaces of alloy steel and

carbon steel RV, RCS piping, and pressurizer components under exposure to inside

environmrents'7The staff asked the applicant to-e'xplain why it-considers the Borated Water

Leakage Assessment and Evaluatio'n Programnsutfficient to manage the loss of material 19':

exteral surfaces'of alloy'steel and carbbn steel RCS piping and fitting components, particularly -

if aging mechanisms other than boric acid leakage and boric acid-induced wastage are known

to induce the loss of material aging effect. The staff identified this issue as RAI 3.1.3.1.2-1,

Part b, which also applied to the evaluation of thfe loss-of material in alloy steel or carbon steel

RCS piping or pressurizer components under external exposure to the inside enrvironment.-

In its review of the applicant's response to Part a of RAI 3.1.3.1.2-1, dated April 16, 2004, the

staff concurred with the applicant that the loss of material due to general corrosion is not an'

AERM for the external surfaces of ASME Code, Class 1, carbon steel or low-alloy steel RCS -

piping and fitting comrponernts because of the high bperating temperatures of the components

and because precipitation on the external surface's was unlikely. In its response to Part b of

RAI 3.1.3.1.2, dated April 16, 2004,'the applicant indicated that an AMP is not necessary for'

managing general corrosion in these components because general corrosion is not identified asan applicable agirig effect for the oripo'nents. . Based on the staff's review of the applicant's

response to RAI 3.1.3.1.2-1, Part a, and 6oncurrence' that general corrosion is not an agingeffect of concern for the external surfaces of carbon steel/low-alloy steel RCS piping and fitting

components, the staff agrdesthat ar'AMP-is not'necessary to manage general corrosion in the

external surfaces of carbon steel or low-alloy steel RCS piping and fitting components.

Therefore, RAI 3.1.3.1.2, Part b, is resolved.

As discussed in Sections 3.0.3.1 and 3.0.31.1 of this SER, industry experience has

demonstrated that the loss of material due to boric acid leakage and boric acid-induced --

wastage (i.e., boric acid-induced corrosion) may occur in the external surfaces of ASME Code,

Class 1, low-alloy steel and carbon steel components that could potentially be exposed to leaks.

to the reactor coolant (i.e., leaks of the borated water). The NRC issued GL 88-05 to address

the impacts of this issue on the PWR industry. Based on this operating experience, Section IV

of GALL, Volume -2, identifies that the loss of material due to boric acid corrosion is an AERM

for external surfaces of carbon steel and low-alloy steel components. The staff concludes that

crediting the Borated Water Leakage Assessment and Evaluation Program with the

management of the loss of material due to boric acid leakage and wastage for the surfaces of

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low-alloy steel or carbon steel RCS piping and fitting components that are exposed to the inside

environment is'acceptable because it is consistent with GALL, Volume 2, and industry

experience. The staff evaluates the Borated Water Leakage Assessment and Evaluation

Program in Sections 3.0.3.1 and 3.0.3.1.1 of this SER.

The staff has reviewed the applicant's AMRs for evaluating the loss of material in ASME Code,

Class 1, RCS piping and fitting components that are made from carbon steel or low-alloy steel

materials and that are exposed to the inside environment. The staff concludes that the ' ;

applicant has provided an acceptable technical basis for concluding that the loss of material

due to general corrosion is not an applicable AERM for the external component surfaces that

are exposed to the inside environment. The staff also concludes that the applicant has credited

an acceptable AMP with managing the loss of material fromthe external surfaces of carbon

steel or low-alloy steel RCS piping and fitting components that could potentially be exposed to

borated reactor coolant.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent'

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

Loss of Material in NiCrFe. Stainless Steel, and CASS RCS Picina and Pressurizer

Components That Are Exposed Externally to Inside (Atmospheric) Environments

Summary of Technical Information in the Application

In Table 3.1.2-3 of the LRA, the applicant provided its AMRs for evaluating the effects of aging

that apply to NiCrFe and stainless steel ASME Code, Class 1, piping and pressurizer

components that are'exposed-extemally to the inside (atmospheric) environment. The'

applicant concluded in these AMRs that exposure of the external surfaces of the NiCrFe and..

stainless steel RCS piping and fitting components to the inside environment will not result' in any

aging effects that require management during the period of extended operation for the FNP

units. The applicant designated these AMRs as note G.

The scope of this commodity'group assessment includes the following components:

* reactor coolant loop piping (CASS)

* piping and components less than NPS 4 (stainless steel)

* piping and components greater than or equal to NPS 4 (stainless steel)

* Class 1 valve bodies (stainless steel)

flow orifice/elements Class 1 (stainless steel)

RCP pump casing (CASS)

* RCP main closure flange (CASS)

* 'pressurizer instrument nozzles and heater well nozzles (stainless steel)

* pressurizer nozzle safe ends (stainless steel with Alloy 82/182 welds and buttering)

* piping-non-Class 1 (stainless steel)

* valve bodies-non-Class 1 (stainless steel)

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to
The applicant concluded that there are no aging effects that require aging management for the

outside surfaces of NiCrFe, CASS, and stainless steel RCS piping and pressurizer components

that are exposed externally to the inside environment. Nonbolted ASME Code, Class 1, NiCrFe

and stainless steel materials'are designedto resist mechanisms that may precipitate corrosioninduced cracking or loss of material under exposure to moist, damp, or wet air environments.

Identification of Aging Effects

Volume 2 of the GALL Report does not list an AERM because of the internal atmosphere of

containment for this commodity group of items (designated as note G in Table 3.1.2-3 of the '

LRA). Secondly, published data and industry experience indicate that a large variety of -

stainless steels suffer no loss'of material 'or detrimental effects from environments of oxygen or

inert atmospheres such as those encountered in a PWR containment. Based on industry

experience and consistent with GALL, Volume 2, the staff considers the designation of no aging

effect for this commodity group inside containment acceptable.

Aging Management Programs or Activities Credited with Aging Management

The applicant did not credit any AMPs for.tthe'management of loss of material or cracking in the

surfaces of nonbolted ASME Code, Class 1, NiCrFe and stainless steel components under

exposure to the inside environment. -Since these components are designed to resist corrosion

under exposure to air environments, the staff concurs that aging management is not necessary

for the surfaces of these components that are exposed to the-inside environment. -Based on

industry experience and consistent with GALL;, Volume 2, the staff considers the designation of

no aging program for this'commodity'group inside containment acceptable.

The staff has reviewed the applicant's AMRs for evaluating whether loss of material is an aging

mechanism that requires aging management for the outside surfaces of NiCrFe, CASS, and

stainless steel RCS piping and pressurizer components that are exposed externally to the -

inside environment. The staff has determined that the applicant provided an acceptable basis

for concluding that there is no aging mechanism for this commodity group. The staff therefore

concludes that the applicant has appropriately designated that there is no AMP f6r this

commodity group, consistent with GALL; therefore, the staff finds this approach acceptable.

Conclusion '- .:

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3). .- ' -

3.1.2.3.4 Steam Generators Aging Management Review Results.

'Surriimrv of Technical Information in the -Anplication -

In LRA Section 3.1.2.1.4, the applicant identified the materials, environments, and AERMs. The

applicant identified the following programs that handle the AERMs for the SG components:

Water Che'rnistry Control Program '.'. --

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* Inservice Inspection Program

* NiCrFe Component Assessment Program

* Steam Generator Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.2.4-1 of the LRA, the applicant summarized the AMRs for the SG components and

identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information in LRA Section 3.1,

Table 3.1.2-4, and Appendix B to determine if the applicant demonstrated that it will manage

the effects of aging adequately so that the intended functions of the SG components will be

maintained consistent with the CLB throughout the period of extended operation.

Aging Effects

The staff reviewed and evaluated the applicability of the aging effects listed in LRA Table

3.1.2-4 for the SG components within the scope of license renewal.;

In LRA Section 3.1.2.2.1, "Cumulative Fatigue Damage," the applicant stated that it uses a

TLAA to manage fatigue for several components in the SGs. Title 10, Section 54.3, of the

Code of Federal Regulations'(1 0 CFR 54.3) defines TLAAs, which must be evaluated in

accordance with 10 CFR 54.21 (c)(1). The Fatigue Monitoring Program manages the fatigue

TLAA for fatigue-sensitive safety Class 1 components having evaluations based on the current

operating term. The GALL Report lists several SG components with fatigue as an aging effect

and bounded by a TLAA. Section 4.3 of this SER reviews and evaluates the fatigue TLAA.

Components Not Consistent with the GALL Report

The GALL Report does not evaluate the following SG components; the applicant's LRA Table

3.1.2-4 denotes that the GALL Report evaluates neither the component, nor the materialenvironment combination:

* Alloy 690 thermally treated channel divider plate (LRA page 3.1-72)

* carbon steel primary moisture separator and sludge collector assembly (LRA page

3.1-74)

* Alloy 690 thermally treated primary nozzle dam rings (LRA page 3.1-75)

* carbon steel secondary moisture separator assembly (LRA page 3.1-75).

* alloy steel secondary-side manways, manholes, inspection ports, and covers (LRA page

3.1-75)

* carbon steel stayrod assemblies (LRA page 3.1-75)

* Alloy 690 thermally treated steam outlet flow limiter (LRA page 3.1-76)

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II
* -'carbon'steel tube bundle wrapper and support assembly (LRA page 3.1-76)

* alloy steel tubesheet clad with Alloy 52/152 on primary side (LRA page 3.1-77)

By letter dated March 22, 2004, in RAI 3.1.2.4-1, the staff requested that the applicant discuss

which program it would use to detect cracking and loss of material in the Alloy 690 thermally.

treated components in order to assess the adequacy of the Water Chemistry Control Program.

The components include the channel divider plate,-primary nozzle dam rings, and steam outle6t

flow limiter. The staff requested that the applicant'discuss the program it will use to detect.

cracking and loss of material in these SG components., The staff requested that the applicant

discuss how it will use this program to detect degradation, thereby verifying that the Water

Chemistry Control Program alone can effectively manage aging of these components during

the'period of extended operation (e.g., water chemistry control is augmented with an inspection

to detect the aging-effects, or the Water Chemistry Control Program has a one-time inspection

which includes this raterial-environment combination); The staff also requested that the

applicant identify the aging mechanisms responsible for the aging effects listed for these

components. - -

In its response to RAI 3.1.2.4-1, dated April 22, 2004, the applicant responded that it credited

only the Water Chemistry Control Program with management of cracking and loss of material

for the replacement SG channel divider plate, primary nozzle dam rings, and steam outlet flow

limiters.' The aging mechanism'associated with cracking is SCC, and the aging mechanisms

associated with loss-of material are crevice corrosion and pitting. The inspection of these

components does not augment the Water Chemistry Control Program; the applicant justified

this' position by stating that SNC has conservatively considered cracking and loss of material as

aging effects that require management for these components, and that these aging effects are

unlikely to occur with the existing chemistry controls provided by the applicant's Water,

Chemistry Control Program.' The applicant stated that these SG components are fabricated

from thermally treated Alloy 690 base metal and Alloy 52/152 weld materials, and a review of

the available industry operating experience indicates that no cracking or loss of material in

thermally treated Alloy 690 base metal and Alloy 52/152 weld materials has occurred to date in

the PWR primary and secondary environments. -The applicant also noted that available

experimental data and industry experience associated with Alloy 690 base metal and Alloy

52/152 weld materials indicate that the primary and secondary chemistry c iontrols implemented

by the applicant's Water Chemistry Control Program are sufficient to prevent SCC, pitting, and

crevice corrosion of these SG components. Regarding SCC, the applicant stated that a

number of industry studies indicate that the increased chromium content and improved

microstructure of thermally treated Alloy.690 base metal and Alloy 52/152 weld materials result

in a significant increase in resistance to' PWSCC over mill-annealed Alloy 600 base metal and

Alloy 82/182 weld materials.

Regarding pitting and crevice corrosion, the applicant stated that the surfaces of components

made from these alloys exhibit a dense passivation layer, which protects the material from the

loss of material due to localized corrosion, especially in the pure primary water and main- steam

environments. 'Furthermore, the applicant stated that the components addressed bythis&RAI

are not in locations that have been associated with significant degradation, even when less

corrosion-resistant mill-annealed Alloy 600 base metal and Alloy 82/182 weld materials are

utilized. Any degradation of the applicant's replacement SG Alloy 690/52/152 materials is

.3-135
expected to occur in areas where higher stresses and more aggressive environmental

conditions exist, such as the jube-to-tubesheet expansion region, tube-to-tube support plate

intersections, and primary nozzle-to-safe-end welds. Existing inspections and evaluations of

these and other corrosion-prone locations will provide a leading indication of any susceptibility

of thermally treated Alloy 690 base metals and Alloy 52/152 weld materials to corrosion in the

borated water and main steam environments. The applicant monitors industry operating

experience and initiates inspection activities as needed. In addition, SNC noted that the

compon ents addressed by this RAI are internal to the SGs and do not perform an RCPB.

function. Table 3.1.2-4 of the LRA lists the applicable component intended functions for each

component type. Cracking or loss of material in these components is only significant for safety,

if the degradation results in a loss of structural integrity which has not been observed because

of the highly corrosion-resistant nature of Alloy 690 materials.

For the channel divider plate, the applicable component intended functions are flow distribution

and structural support. The loading on the channel divider plate is the differential pressure

across the divider plate and is equivalent to the pressure drop across the SG tube bundle.

Therefore, stress on the divider plate during normal operations is very low. Pitting, SCC, or

crevice corrosion of the channel divider plate would only result in minimal leakage from the

higher pressure hot-leg inlet to the lower pressure cold-leg outlet and would not be significant

for safety.

For the primary nozzle dam rings, the applicant stated that structural support is the applicable

component intended function; When nozzle dams are not installed, the loading on the primary

nozzle dam rings is low, and results from the minor differential pressure/frictional losses

resulting from primary loop flow across the ring. When nozzle dams are installed (during an

outage), the loading on the rings is also low and is equivalent to the static head of the reactor

vesseVrefueling cavity water level. Significant degradation in a nozzle dam ring would be

identified during nozzle dam installation. Leakage across the nozzle dam and ring is monitored.

In addition, failure of a nozzle dam assembly would not drop the RCS water level below the

midloop level; core coverage and cooling would be maintained. The applicant stated that flow

restriction is the applicable component function for the steam outlet flow limiters. In the high

purity main steam environment, only trace amounts of detrimental ionic impurities are present,.

and very low oxygen content exists. In this environment, SCC, pitting; and crevice corrosion

are highly unlikely. Even so, any cracking, pitting, or crevice corrosion is not likely to affect the

flow restriction function, since only structural integrity of the limiter must be maintained.

The staff finds that the applicant's Water Chemistry Control Program adequately manages

cracking and loss of material in the channel divider plate, primary nozzle dam rings, and steam

outlet flow limiter. These SG components are made from corrosion-resistant materials, which

have shown no instances of cracking or loss of material, based on industry experience. In

addition, inspections of the Alloy 690 thermally treated SG tubes in highly stressed locations will

provide a leading indication of the susceptibility of these materials to degradation.

With respect to the primary moisture separator and sludge collector assembly, secondary

moisture separator assembly, secondary-side manways, manholes, inspection ports, and

covers, stayrod assemblies, tube bundle wrapper and support assembly, and tubesheet, the

staff finds that the applicant has correctly identified the aging effects of cracking and/or loss of

material for these components, and that the identified AMPs will adequately manage these

aging effects. The staff based its findings on the known aging effects for these materials

3-136

It
exposed to treated and borated water environments.'

Components Consistent with the GALL Report with Exceptions

The GALL Report only partially evaluates the following SG components, which LRA Table

3.1.2-4 denotes as such' -

* alloy steel/stainless steel clad charinel head and integral primary nozzles (LRA page

3.1-72)

* - alloy steel secondary closure bolting (LRA page 3.1-73)

* carbon steel, alloy steel, and Alloy 690 thermally treated feedwater distribution assembly

(thermal sleeve, piping and fittingsispargers, support structure) (LRA page 3.1.73)

* alloy steel feedwater inlet nozzle (LRA page 3.1.73)

* stainless steel (with NiCrFe Alloy 52/152 buttering and welds) primary inlet and outlet

nozzle safe ends (LRA page 3.1-74) - -

* alloy steel/stainless steel primary manway covers and disc inserts (LRA page 3.1-74)

* '- alloy steel secondary shell penetrations (LRA page 3.1-76) -: -,

* stainless steel, Alloy 690 thermally treated tube support plates, flow distribution baffles,

and antivibration bars (LRA page 3.1-77)

* Alloy 690 thermally treated U-tubes (includes welded tube plugs) (LRA page 3.1-78)

* alloy steel/Alloy 52/152 upper head with integral steam nozzle (LRA page 3.1-79)

* alloy steel upper shells, lower shells, and transition cones (LRA page 3.1-79)

Table 3.1.2-4 of the LRA, page 3.1-73, lists no aging effect for secondary closure bolting. In

addition, the applicant stated in note 8 to the table that the secondary handholes are removed

to facilitate sludge'removal and visual inspection; therefore, the applicant concluded that the

loss'"f bolting preload is not'an AERM. However, the staff notes that the secondary ,handhole

bolting may still be subjected to'a loss of.prestress. The staff also notes that GALL AMP

XI.M18, "Bolting Integrity," 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. -Comprehensive bolting integrity

programs encompass'all safety-related programs as delineated by NUREG-1339, "Resolution

of Generic-Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants." In

addition, comprehensive rriiainteaiance for bolting is managed in accordance with EPRI

TR-1 04213, "Bolted Joint Maintenance and Applications Guide." Therefore, by letter dated

March 22,'2004, in RAI 3.1 '2.4-2, the staff requested that the applicant provide details.(and a,

technical basis) on how it manages the loss of prestress of secondaryclosure bolting.- -

: to RAI d e , ,r 2, 2 0 4, - . ... ; ..

In its response to RAI 3.1.2.4-2, dated April 22, 2004, the applicant responded that secondary-

'3-137
I it

side closure bolting is used to secure covers for two 16-inch inner diameter (ID) manways, six

6-inch ID handholes, and four 4-inch ID inspection ports. The bolting used to secure the

manway covers is 1.25 inches in diameter, and the bolting used to secure the handhole and

inspection port covers is 1 inch in diameter. This secondary-side closure bolting is fabricated

from ASME SA-1 93 Grade B7 alloy steel. The applicant stated that it listed no aging effects for

the replacement SG secondary-side closure bolting because its AMR for. these components

determined that no AERMs exist for these bolts. The applicant explained the technical basis for

this conclusion as it relates to the loss of prestress. Work performed as a part of the EPRI

MRP indicates that secondary, steady-state creep only occurs for alloy steels when operating

temperatures exceed 40 to 50 percent of the melting temperature (in absolute units). A

conservative lower bound melting temperature for alloy steels is 2500 OF (2959 OR). The SNC

conservatively used 725 OF as the temperature below which no steady-state creep of the alloy

steel bolting will occur. The applicant's operating temperatures are below this threshold

temperature. The SG secondary-side closures are routinely disassembled to provide access

for cleaning and inspection, and no long-term accumulation of creep effects is expected to

occur since these closure joints are disassembled and reinstalled periodically.

The applicant stated that leakage at joints is typically associated with improper joint installation,

joint design, or gasket effects, not relaxation of the bolting materials. The applicant's

procedures for joint installation incorporate industry guidance from EPRI NP-5769, "Good

Bolting Practices," and EPRI TR-1 04213. These procedures provide for the use of proper

lubricants and sound bolt torquing practices. However, these procedures are considered to be

a part of normal maintenance practices and are not credited as a specific AMP for license

renewal. Lastly, the applicant stated that its operating experience with the SGs has not

indicated any problems with the loss of prestress in the SG secondary-side closures.

The staff finds that the loss of prestress of secondary closure bolting does not require

management, based on the applicant's AMR, because (1) the bolting is subjected to operating

temperatures below that for creep and bolting is routinely disassembled, thereby essentially

removing the likelihood of long-term accumulation of creep effects, (2) joint installation

procedures are a component of maintenance practice, which is managed in accordance with

EPRI NP-5769 and EPRI TR-104213, and (3) plant operating history has indicated no loss of

secondary closure bolting prestress.

With respect to the channel head and integral primary nozzles, primary inlet and outlet nozzle

safe ends, and U-tubes (including welded plugs), the staff finds that the applicant has correctly

identified the aging effects of cracking and/or loss of material for these components. The staff

based its findings on the known aging effects for these materials exposed to treated and/or

borated water environments.

With respect to the feedwater distribution assembly, primary manway covers and disc inserts,

tube'support plates, flow distribution baffles, and antivibration bars; the staff finds that the

applicant has identified the- aging effects of cracking and/or loss of material for these .

components. The staff notes that the applicant credited-the Water Chemistry Control Program

to manage the aging of these components. In addition, the applicant also credited the SteamGenerator Program for the management of cracking and loss of material for the feedwater

distribution assembly, tube support plates, flow distribution baffles, and antivibration bars.

Therefore, by letter dated March 22, 2004, in RAI 3.1.2.4-3, the staff requested that the

applicant provide details (and a technical basis) on how the program credited for the

3-138 -

1I
management of cracking and/or loss of material'in these SG components will detect cracking

and/or loss of material.

In its-response to RAI 3.1.2.4-3, in a letter dated April 22, 2004, the applicant responded that

the preventive features of the Secondary Water Chemistry Control Program primarily manages .

the loss of material and cracking within the replacement SG secondary-side components,

addressed by'this RAt (i.e., feedwater distribution assembly, tube support plates, flow

distribution baffles, and antivibration bars). -'For these secondary-side components, the,,

applicant's replacement SGs incorporate improvements in the construction materials to address

the degradation issues experienced by the industry. The replacement SGs utilize thermally'

treated Alloy 690 base metal and Alloy 52/152 weld materials (Alloy 600 materials are '

prohibited in' the replacement SGs). -Corrosion-resistant materials (ASME SA-240 Type 405

ferritic stainless steel) were used in the tube support plates and the flow distribution baffle (the

support plates in the original SGs were carbon steel).' Antivibration bars are also constructed

from ASME SA-240 Type 405 ferritic stainless steel. The applicant stated that the feedwater

distribution assembly is an elevated feed ring design and consists of a thermally treated Alloy;

690 thermal 'sleeve which transitions to an elevated feedwater distribution ring pipe constructed

from alloy steel with spray nozzles in lieu of j-tubes.- The spray nozzles are fabricated from '

thermally treated Alloy 690. Industry experience and research demonstrate the reliability of

these materials in the secondary-side environment of the SGs.

The'applicant also stated that the its replacement SGs incorporate design improvements to

reduce scale buildup and deposition of solids (sludge) within the tube bundle, further reducing

the potential for component degradation. The flow distribution baffle increases the flow velocity

across the tubesheet surface'to limit the low velocity region to the center of the tube bundle

near the blowdown intake. The passively operating sludge collector reduces the amo'unt of

sludge deposited within the tube bundle. The tube support plates use broached quatrefoilshaped holes (instead of drilled holes) to improve axial flow and reduce contaminant

concentration at the tube-to-tube support interface.

The applicant stated that the response to RAI 3.1.2.4-5 provides the details regarding how.its'

Steam Generator Program manages aging of the feedwater distribution assembly, tube support

plates, flow distribution baffles,'and antivibration bars. The Steam Generator Prograrri performs

an assessment based upon the applicant's SG design, potential degradation mechanisms, and

related FNP and industry operating experience to establish inspection requirements for

secondary-side internals components; The FNP-specific operating experience includes results

from previous inspections and observations made during cleaning activities (e.g., sludge

lancing and sludge collector cleaning). Where appropriate based on the'conclusions of this

assessment, the applicant may perform visual inspections to detect component degradation.''

The applicant stated that it credits the preventive actions of the Water Chemistry Control

Program for aging management of the primary manway covers and disc inserts in the'6brated

water environment. The Water Chemistry Control Program provides for both a strongly

redu'cing'environment via the addition of oxygen scavengers and strict control of detrimental

ionic species. By design, only the disc inserts are exposed to the primary water environment.

These disc inserts are fabricated from ASME SA-240j;Grade 304 austenitic stainless steel plate

and are held in place by stainless steel screws. These inserts were heat treated after

machining and are not field welded, thus eliminating sensitization issues. -The applicant has

detected no evidence of age-related degradation of the primary manway disc inserts or covers

in the operating experience to date.' In addition, the applicant periodically removes the primary

3-139
manway covers and disc inserts in support of SG primary-side activities (e.g., ECT of the SG

tubes). Their condition is visually assessed as part of these normal activities.

On the basis of the information submitted, the staff concludes that the applicant's Secondary

Water Chemistry Control Program and Steam Generator Program are adequate to detect

cracking and/or loss of material for the replacement SG components because of (1) the use of

materials with improved corrosion' resistence, according to plant and industry experience and

industry research, (2) improved design of replacement SG internal assemblies, and (3) the

effectiveness of the Water Chemistry Program in preventing age-related degradation of these

components.

With respect to the feedwater inlet nozzle, secondary shell penetrations, upper head with

integral steam nozzles, upper shells, lower shells, and transition cones, the staff notes that one

of the environments listed in LRA Table 3.1.2-4 is the inside environment (i.e., exterior surfaces.

inside the containment structure). The staff also notes that no AERMs are listed for these

components. The GALL AMP XI.M10, "Boric Acid Corrosion," states that the program includes

any carbon steel and low-alloy' steel structure or component on which borated water may leak.

In light of recent events at Davis-Besse that involved the leakage of borated coolant water and

the subsequent corrosion of a ferrous component, by letter dated March 22, 2004, in RAI

3.1.3.4-4, the staff requested that the applicant discuss why it did not list the loss of material

due to borated water leakage as an AERM. The staff also asked the applicant to describe the

program credited for managing borated water leakage and corrosion of the exterior surfaces for

these SG components.

In its response to RAI 3.1.3.4-4, dated April 22, 2004, the applicant responded that its

replacement SG upper head with integral steam nozzle, upper shell, transition cone, lower shell,

and feedwater inlet nozzle are not subject to borated water leakage because they are not

located beneath any potential source of borated water.'leakage and are physically separated

from the primary manways. There are no borated water pipelines routed above the SG

cubicles. The applicant's replacement SG primary manways are located on the underside of

the lower channel head. Any borated water leakage from the primary manways would either

remain on the lower head or would drip downward, away from the subject SG subcomponents.

Therefore, boric acid corrosion is not considered plausible for these SG subcomponents. This

SNC position is consistent with NUREG-1801, Volume 2, Section IV.D1. Within this section of

NUREG-1 801, only th'e SG lower head and primary manway component types are associated

with boric acid corrosion. Although NUREG-1 801 includes steam generator upper heads, -

shells, transition cones, and feedwater nozzles, these component types are not associated with

boric acid corrosion.

Recent operating experience at another PWR facility (Catawba) showed cracking in a SG drain

lines on the bottom of the SGs.' These were 1/4 inch drain lines used to drain water out during

plant outages. The FNP SGs'do not have separate bowl drains like Catawba which exhibited

cracking. On the Farley SGs, the bowl drains were replaced with a small hole drilled through

the lip of the nozzles such that the bowl drains into the hot and cold legs on either side of the

SG. Therefore, the potential for bowl drain linre cracking does not apply to FNP.

On the basis of the information submitted, the staff concludes that it is appropriate not to list the

loss of material due to borated water leakage as an AERM for the upper head with integral

steam' nozzle, upper shell, transition cone, lower shell, and feedwater inlet nozzle in the FNP

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I

SGs.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained c6nsistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.1.3 -Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that the

aging effects associated with the reactor vessel, internals, RCS components, ans steam

generators 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). ; staff also .:. reviewed . the appli e '' ad cn 

The staff also reviewed the applicable ESAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging of the

reactor vessel, internals, and RCS components, as required by 10 CFR 54.21 (d).

3.2 Aging Management of Engineered Safety Features Systerns

This section of the SER documents the staff's review of the applicant's AMR results for the

engineered safety features system components and component groups associated with the

following systems: - - -

* containment spray

* containment isolation

* emergency core cooling

3.2.1 Summary of Technical Information in the Application

In Table 3.2.1, "Summary of the Aging Management Evaluations for Engineered Safety.

Features in Chapter V of NUREG-1 801," the applicant provided a summary comparison of its

AMRs with the AMRs evaluated in the GALL Report for the engineered safety features system

components and component groups that are relied on for license renewal.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluati6onof plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. The applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report in 2001.

The applicant conducts its ongoing review of plant-specific and industry operating experience in

accordance with the FNP, Units 1 and 2, Operating Experience Program.

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3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the engineered safety features system components

that are within the scope of license renewaland subject to an AMR will be adequately managed

so that the intended functions will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

The staff performed an audit and review to confirm the applicant's claim that certain identified

AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report. However, the staff did determine that the applicant presented

applicable material in the LRA and identified the appropriate GALL AMPs. Section 3.0.3 of this

SER documents the staff's evaluations of these AMPs. The FNP Audit and Review Report,

summarized in Section 3.2.2.1 of this SER, documents the details of the staff's evaluation of the

audit and review for these AMRs.

The staff also performed an audit and review of those AMRs that were consistent with the GALL

Report and for which further'evaluation is recommended.' During the audit and review, the staff

evaluated that the applicant's further evaluations were consistent with the acceptance criteria in

Section 3.2.2.2 of the SRP-LR. The FNP Audit and Review Report, summarized in Section

3.2.2.2 of this SER, documents the details of the staffs evaluation of the audit and review for

these AMRs.

The staff conducted a technical review of the remaining AMRs that were not consistent with the

GALL Report. In the review, the staff evaluated whether the applicant identified all plausible

aging effects and listed the appropriate aging effects for the material-environment combinations

specified. Section 3.2.2.3 of this SER documents the details of the staffs review and

evaluation of these AMRs that are not consistent with the GALL Report.

Finally, the staff reviewed the AMP summary descriptions in the FSAR Supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

engineered safety system components.

Table 3.2-1 below summarizes the staffs evaluation of components, aging effects/mechanisms,

and AMPs listed in Section 3.2 of the LRA and addressed by the GALL Report.

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

Report

: Component Group2'., . :. SAgIng Effect/.:.. - AMP in GALL- XAMP In LR be 'T {Staff Evaluation '.'

-;M'Mech'nI man - . ep b" ' I .. ,

Piping, fittings, and Cumulative fatigue TLAA, evaluated in 10 CFR 54.21 Consistent with

valves in damage accordance with (c)(1)(i) analyses GALL, which ' emergency core 10 CFR 54.21(c) remain valid recommends further

cooling system evaluation. (See

Item Number Section 3.2.2.2.1)

3.2.1-1 .

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1
Component Group ' g1ng -`n- in G- ' LEffecI LA i -' Sf v>Stf E iui-t . s~x-b- ---;^---X*S-' MechanIs ;:-i<<-t;I '--! <sat-s,r;'

Components In Loss of material Plant specific . One-Time Consistent with

containment spray' due to general Inspection Program GALL, which

(PWR only), - corrosion (Appendix B.5.5); recommends further,

standby gas - External Surfaces evaluation. (See

treatment (BWR Monitoring Program Section 3.2.2.2.2)

only), containment (Appendix B.5.3)

isolation, and -

emergency core

cooling systems

Item Number

3.2.1.3

Components in ' Loss of material Plant specific One-Time Consistent with

containment spray due to pitting and Inspection Program GALL, which

(PWR only), crevice corrosion (Appendix B.5.5) recommends further.

standby (BWR evaluation. (See

only), containment ; Section 3.2.2.2.3)

isolation, and -

emergency core

cooling systems

Item Number

3.2.1-5

Containment Loss of material Plant specific None Consistent with

isolation'valves and due to MIC - .': GALL, which

associated piping: recommends further

Item Number - evaluation. (See

3.2.1-6 . Section 3.2.2.2.4)

High-pressure Loss of material Plant specific One-Time - Consistent with

safety injection due'to erosion ' ' . .Inspection Program GALL, which

(charging) pump (Appendix B.5.5) recommends further

miniflow orifice . -- evaluation. (See,

Item Number -' - Section 3.2.2.2.6)

3.2.1-8 : -, --

External surfaces of Loss of material Plant spec ic Extemal Surfaces Consistent 'with'

carbon steel - due to general ; . . Monitoring Program GALL, which ;

components - corrosion * (Appendix B.5.3) - recommends further

Item Number , . - -; - ; . evaluation. (See

3.2.1-10 - - ' ,. - . Section 3.2.2.2.2)

Piping and fittings Lois of fracture' 1Thrmal aging' None' ' - Consistent with

of CASS In toughness due to - rembrittlement of. . . GALL, which

emergency core thermal aging, - CASS ... recommends no

cooling systems embrittlement ; . .... - . . further evaluation:

Item Number (See Section3.2.1-11 _ 3.2.2.1)

Components Loss of material 000W system None Consistent with*,

serviced by open- due to general, GALL, which

cycle cooling pitting, and crevice recommends no

system corrosion, MIC, and * * > further evaluation.

Item Number biofouling; buildup (See Section

3.2.1-12 - - of deposit due to . - i ; . . ;; i: 3.2.2.1)

biofouling. .. i . --

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Component GR g ng Effetk! N H i In GALL"" '- a + AMP I AK > ->i;jt;,',trf, , _9-i~Msan !. fo |e , rd g, 1~ a, *SAd

Components Loss of material CCCW system Water Chemistry Consistent with

serviced by closed- due to general, Control Program GALL, which

cycle cooling pitting, and crevice (Appendix B.3.2) recommends no

system corrosion further evaluation.

Item Number (See Section

3.2.1-13 3.2.2.1)

Pumps, valves, Crack initiation and Water chemistry Water Chemistry Consistent with

piping, fittings, and growth due to SCC Control Program GALL, which

tanks in (Appendix B.3.2) recommends no

containment spray further evaluation.

and emergency (See Section*

core cooling 3.2.2.1)

systems

Item Number

3.2.1-15

Carbon steel Loss of material Boric acid corrosion Borated Water Consistent with

components due to boric acid Leakage GALL, which -

Item Number corrosion Assessment and recommends no

3.2.1-17 Evaluation further evaluation.

Program (Appendix (See Section

B.3.5) 3.2.2.1)

Closure bolting in Loss of material Bolting integrity Extemal Surfaces Consistent with

high-pressure or due to general Monitoring Program GALL, which

high-temperature corrosion; crack (Appendix B.5.3) recommends no

systems initiation and growth further evaluation.

Item Number - due to cyclic (See Section

3.2.1-18 loading and/or SCC 3.2.2.1)

The staff's review of the applicant's engineered safety features system and associated

components followed one of several approaches. One approach, documented in Section

3.2.2.1, involved the staff's review of the AMR results for components in the engineered safety

features system that the applicant indicated are consistent with the GALL Report and do not

'require further evaluation. Another approach, documented in Section 3.2.2.2, involved the

staff's review of the AMR results for components in the engineered safety features system that

the applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in Section 3.2.2.3, involved the staff's review of

the AMR results for components in the engineered safety features system that the applicant

indicated are not consistent with the GALL Report or are not addressed in the GALL Report.

Section 3.0.3 of this SER documents the staff's review of AMPs that are credited to manage or

monitor aging effects of the engineered safety features system components.

3.2.2.1 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Not Recommended

Summarv of Technical Information in the Application

In Sections 3.2.2.1.1 through 3.2.2.1.3 of the LRA, the applicant identified the materials, -

environments, and AERMs. The applicant identified the following programs that manage the

3-144

11
aging effects related to the engineered safety features system components:

* Water Chemistry Control Program

* 'One-Time Inspection Program'

* External Surfaces Monitoring Programr - - -

* Borated Water Leakage'Assessment 'and Evaluation Program

Staff Evaluation

In Tables 3.2.2-1 through 3.2.2-3 of the LRA, the applicant summarized the AMRs for the

engineered safety features systems and identified which AMRs it considered to be corisistent

with the GALL Report.

The staff conducted an audit and review of 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 clairried to be consistent wvith the GALL Report,

are indeed consistent with GALL.- Therefore, the staff finds that the applicant identified :

applicable aging effects that are appropriate for the'material-environment combinations listed.

On the basis of its audit and review, the staff concludes that the applicant has demonstrated

that the effects of aging will be adequately'managed so that the intended functions will be'

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). ' '

Conclusion

The staff has evaluated the applicant's claim of consistency with the GALL Report. 'The staff

reviewed information pertaining to the' applicant's consideration of recent operating experience

and proposals for managing associated aging effects. 'On the basis of its'review, the staff finds

that the applicant has demonstrated that the 'effects of aging for these components will be

adequately managed so that their intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).- .. . .,4 4 . ' .. 4 ; . .

3.2.2.2 -AMR Results That Are Consistent with the GALL Report,- for Which Further Evaluation

Is Recommended - ' :- - .' . : '. ' '' - ' - ' :. 4, S j' - -: -

Summary of Technical Inforniation in the Abblication,'

In Section 3.2.2.2 of the LRA, the applicant provided further evaluation of aging management

as recommended by the GALL Report for engineered safety features systems.' The applicant

discussed how it will manage the following'agin'g effects' - -

* cumulative fatigue"damage - l -

*~ loss I 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 material properties due to elastomer degradation

* lical loss of material cdue to erosion::

* -buildup of deposits due to corrosion ¢ . - -

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a

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 analysis to determine whether it adequately

addressed these issues. In addition, the staff audited the applicant's further evaluations against

the criteria contained in Section 3.2.2.2 of the SRP-LR. The FNP Audit and Review Report

documents the details of the staff's audit and review.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections.

3.2.2.2.1 Cumulative Fatigue DamageAs stated in the SRP-LR, fatigue is a TLAA, as defined in 10 CFR 54.3, and 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 Section 3.2.2.2.2 of the LRA, the applicant addressed the loss of material due to general

corrosion that could occur in the containment isolation and emergency core cooling systems, as

well as on 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 and emergency core cooling systems, as well as on the external

surfaces of carbon steel components. The GALL Report recommends further evaluation on a

plant-specific basis to ensure that the aging effect is adequately managed.

The applicant stated that the scope of components addressed by this discussion includes

carbon steel components in the emergency core cooling and containment isolation systems.

The containment spray system does not contain carbon (or low-alloy) steel components. except

for bolting and encapsulation vessels. The applicant credited the One-Time Inspection- -

Program (AMP B.5.5) for carbon steel components in an air/gas (wetted) environment and the

External Surfaces Monitoring Program (AMP B.5.3) for the loss of material due to general

corrosion for the external surfaces of carbon steel components and bolting.

Sections 3.0.3.1 and 3.0.3.3.2 of this SER document the staff's review of the One-Time

Inspection Program and the External Surfaces Monitoring Program, respectively. The

One-Time Inspection Program covers components from these systems, and the program is

consistent with GALL AMP XI.M33, "Selective Leaching of Materials." The scope of the

External Surfaces Monitoring Program includes components from these systems and depends

on visual inspection to detect degradation. The staff concludes that the plant-specific program

credited by the applicant for this line item is acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving the management of the loss of material due to general corrosion, as recommended in

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the GALL Report. Since the applicant's AMR results are otherwise consistent with the GALL

Report, the staff'finds 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).

3.2.2.2.3 Local Loss of Material Due to Pitting and Crevice Corrosion

In Section 3.2.2.2.3 of the'LRA, the applicant addressed the local loss of material due to pitting

and crevice corrosion that could occur in the interior and exterior surfaces of the carbon steel

and stainless steel components in the containment isolation system and on the outer surface of

the stainless steel refueling water storage tank.

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 the buried portion' of the refueling water tank's external surface.- The'

GALL Report recommends further evaluation to ensure that the aging effect is adequately

managed. -

The applicant'stated that the environmerits'in the'containment isolation system are dry gas and

air/gas (wetted). In addition, the applicant stated that component surfaces exposed to a dry

gas environment do not need aging management for the local loss of material due to pitting and

crevice corrosion. For components in the containment isolation system with an air/gas

environment, the applicant credited the One-Time Inspection Program (AMP B.5.5) with

managing the aging effect of a loss of material due to pitting and crevice corrosion.

Section 3.0.3.1 of this SER documents the staff's review of the One-Time Inspection Program.

The staff concludes that the plant-specific program credited by the applicant for this line item is

acceptable.

The applicant stated that the stainless steel refueling water storage tank is located above the

ground; therefore, this aging mechanism does not apply. The staff concurs with this

conclusion.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving the management of the local loss-of material due to pitting and crevice

corrosion, as recommended in the GALL Report. Since the applicant's AMR results are

otherwise consistent with the GALL Report, the staff finds that the intended functions will be.

maintained consistent with the CLB for theperiod of extended operation, as required by

10 CFR 54.21(a)(3). -

3.2.2.2.4 Local Loss of Material Due to Microbiologically Influenced Corrosion

In Section 3.2.2.2.4 of the LRA, the applicant addressed the local loss of material due to MIC. * . , X . . ; . - - ; * --

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 other chapters of the GALL

Report do not address. The GALL Report recommends further evaluation to ensure that the

aging effect is adequately managed.

The applicant stated that it addressed the containment isolation system components that have

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an environment of treated water, raw water, or liquid waste as part of other systems. The

components applicable to this line item include those with exposure to a dry gas or an air/gas

(wetted) environment. For these environments, the loss of material due to MIC is not a valid

aging effect.

Because microbiological organisms need a water environment, and because the components

are exposed to a dry gas or an air/gas environment, the staff finds that this aging effect does

not apply to FNP.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving the management of the local loss of material due to MIC, as recommended in

the GALL Report. Since the applicant's AMR results are otherwise consistent with the GALL

Report, the staff finds 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).

3.2.2.2.5 Changes in Material Properties Due to Elastomer Degradation

The applicant stated that this issue applies only to BWRs; therefore, it does not apply to FNP.

The staff concurs with this assessment.

3.2.2.2.6 Local Loss of Material Due to Erosion

In Section 3.2.2.2.6 of the LRA, the applicant addressed the local loss of material due to

erosion that could occur in the high-pressure safety injection pump miniflow orifice.

Section 3.2.2.2.6 of the SRP-LR states that a local loss of material due to erosion could occur

in the high-pressure safety injection 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 system. The GALL Report recommends further evaluation to ensure that the aging

effect is adequately managed.

The applicant stated that this aging mechanism and effect will apply only to pumps that are

normally used as charging pumps in the chemical and volume control systems. The applicant

credited the One-Time Inspection Program (AMP B.5.5) as the plant-specific program that will

manage this aging effect. The applicant stated that the six pumps are rotated to equalize run

time, so each miniflow orifice is susceptible to this aging effect in-a similar manner. The onetime inspection will be performed on a bounding CVCS letdown- orifice or charging/SI pump

miniflow orifice, which would be a good indicator for all the others.

Section 3.0.3.1 of this SER documents the staff's review of the One-Time Inspection Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving the management of the loss of material due to erosion, as recommended in the

GALL Report. Since the applicant's AMR results are otherwise consistent with the GALL

Report, the staff finds that the intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.2.2.2.7 Buildup of Deposits Due to Corrosion

The applicant stated that this issue applies on y to'BWRs; therefore, it does not apply to FNP.

The staff concurs with this assessment. '-

Conclusion '

On the basis of its audit and review, the staff finds that the applicant's further evaluationis'

conducted in accordance with the GALL Report are consistent with the acceptance criteria in

Section 3.2.2.2 of the SRP-LR. Since the applicant's AMR results are otherwise consistent with

the GALL report, the staff finds that the applicant has demonstrated that the'effects of aging will

be adequately managed so that the intended fdn6tion(s) will be rmaintained consistent'with the

current licensing basisjfor the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3 AMR Results That Are Not Consistent With or Not Addressed in the GALL Report

3.2.2.3.1 Containm'ent Spray System AMR Results

Summary of Technical Information in the Application

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 manag6 the AERMs for'the

containment spray system components:

- Water Chemistry Control Program

* 1ne-Time Irisliection Program

* Exteirial Surfaces'Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.2.2-1 of the LRA, the applicant sumnmariied the 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 AMRs of the containment spray system comnponrents relating to those''

combinations of materials, environrnents, novponents, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A throuigh E in LRA Table

3.2.2-1. Section 3.2.2.1 of this SER documents the staff's evaluation.

The technical staff reviewed the AMR of the cormbinations of containment spray systemcomponents, materials, environments, and AERMs that are iot addr6ssed ini thd GALL Report.

These combinations use notes F through J in LRA Table 3.2.2-1. For the combinations using

notes F through J, the staff determined that the applicant identified -al applicable AERMs and

credited appropriate AMPs for managing these effects. - The staff also reviewed the applicable

FSAR Supplements for the AMPs to ensure that they adequately describe the AMPs.

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Aging Effects

Table 2.3.2.1 of the LRA lists individual system components for the containment spray system

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 eductors, encapsulation vessel, flow orifice, flow

element, piping, pump casings, spray nozzles, valve bodies, and vortex breakers.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Stainless steel components exposed to borated water and wetted air/gas environments

are subject to the aging effect of loss of material.

* Carbon steel components exposed to air/gas or inside environments are subject t6 the

aging effect of loss of material.

* Stainless steel components exposed to air/gas, inside, or embedded environments

experience no aging effects.

During its review, the staff determined that it needed additional information to complete its

evaluation of the containment spray system. Section 3.2.2.3.4.1 of this SER contains the staff's

evaluation of the loss of material for stainless steel and stainless steel clad components in a

borated water environment. Section 3.2.2.3.4.2 of this SER provides the staff's evaluation of

the loss of preload and cracking for closure bolting.

On the basis of its review of the LRA, the staff finds that the aging effects of the containment

spray system component types given above that are not addressed by the GALL Report are

consistent with industry experience for these material-6nvironment combinati6ns. The~ staff did

not identify any omitted aging effects for the combinations in LRA-Table 3.2.2-1 using notes F

through J. Therefore, the staff finds that the applicant has identified the appropriate aging

effects for the materials and environments associated with the above components in the

containment spray system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they. are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.2.2-1 of the LRA identifies the following AMPs for managing the aging effects described

above for the containment spray system:

* Water Chemistry Control Program (LRA Section B.3.2)

* One-Time Inspection Program (LRA Section B.5.5)

Sections 3.0.3.2.1 and 3.0.3.1, respectively, of this SER provide the staff's review of these

AMPs.

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On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effebts of the containment spray system component types that

are not addressed by the GALL Report. In addition, the staff finds the program descriptions in

the FSAR Supplement acceptable. -.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the containment spray

system components that are not addressed by the GALL Report, so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21(d).

3.2.2.3.2 Containment Isolation System AMR Results

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 aging effects related

to the containment isolation system components:-- -

* One-Time Inspection Program - * External Surfaces Monitoring Program:

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.2.2-2 of the LRA, the applicant'summarized the 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 AMRs of the containment isolation system components relating to those

combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.2.2-2. Section 3.2.2.1 of this SER documents the staff's evaluation.

The technical staff reviewed the AMR of the combinations of containment isolation system,

components, materials, environrrients,-and AERMs that are not addressed in the GALL Report.

These combinations use notes F through J in LRA Table 3.2.2-2. For the combinations using

notes F through J, the staff determined that the applicant identified all applicable AERMs and

credited appropriate AMPs for, managing these effects. The staff also reviewed the applicable

FSAR Supplements for the AMPs to ensure that they adequately describe the AMPs. -

., , ,! :

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Aging Effects

Table 2.3.2-2 of the LRA lists individual system components for the containment isolation

system that are 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 capillary tubing, piping, and valve

bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel components exposed to an air/gas environment are subject to the aging

effect of loss of material.

* Carbon steel components exposed to a dry gas environment experience no aging

effects.

* Stainless steel components exposed to air/gas, dry gas, and inside environments

experience no aging effects.

During its review, the staff determined that it needed additional information to complete its

evaluation of the containment isolation system. Section 3.2.2.3.4.2 of this SER contains the

staff's evaluation of the loss of preload and cracking for closure bolting.

Table 3.2.2-2 of the LRA does not list the material type for valve bodies located in an inside

environment. In RAI 3.2-1, the staff requested the material type for these valve bodies. In its

response dated May 28, 2004, the applicant's errata sheet for the LRA listed the material type

for the valve bodies as stainless steel. The staff considers this material type acceptable for the

aging management identified in the LRA.

On the basis of its review of the LRA, the staff finds that the aging effects of the containment

isolation system component types given above that are not addressed by the GALL Report are

consistent with industry experience for these material-environment combinations. The staff did

not identify any omitted aging effects for the combinations in LRA Table 3.2.2-2 using notes F

through J. Therefore, the staff finds that the applicant has identified the appropriate aging

effects for the materials and environments associated with the above components in the

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 determined that the FSAR 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:

* Water Chemistry Control Program (LRA Section B.3.2)

One-Time Inspection Program (LRA Section B.5.5)

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Sections 3.0.3.2.1 and 3.0.3.1, respectively, of this SER provide'the staff's review of these

AMPs.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the containment isolation system component types that

are not addressed by the GALL Report. In addition, the staff finds the program descriptions in

the FSAR Supplement acceptable. -

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the containment

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 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they provide an adequate description of the AMPs credited for managing aging in these

components, as required by 10 CFR 54.21 (d).

3.2.2.3.3 Emergency Core Cooling System AMR Results

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. The applicant identified the following programs that manage the aging effects related

to the emergency core cooling system components:

* Water Chemistry Control Program

* One-Time Inspection Program

* External Surfaces Monitoring Program

* 'Borated Water Leakag6 Asiessm6nt and Evaluation Program

In Table 3.2.2-3 of the LRA, the applicant summarized the AMRs for the emergency core

cooling system components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the emergency core'cooling system components relating to

those combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.2.2-3. Section 3.2.2.1 of this SER documents the staff's evaluation.;

The technical staff reviewed the AMR of the combinations of emergency core cooling system

components,' mraterials, environments, and AERMs that are not addressed in the GALL Report.

These combinations use notes F through J in LRA Table 3.2.2-3. For the combinations using

notes F through J, the staff determined that the applicant identified all applicable AERMs and

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I

has credited appropriate AMPs for managing these effects. The staff also reviewed the

applicable FSAR Supplements for the AMPs to ensure that they adequately describe the AMPs.

During the scoping review, in response to NRC Inspection Report Nos. 50-348/2004-007 and

50-364/2004-007, dated June 22, 2004, the applicant added vents for the refueling water

storage tank within the scope of license renewal. The vents are considered an integral subpart

of the tank and consequently are part of the refueling water storage tank (RWST) listed in LRA

Table 3.2.2-3. The applicant stated that the aging effect for the stainless steel vents in an

air/gas (wetted) environment is loss of material, and that this aging effect will be managed by

the One-Time Inspection Program.

By letter dated August 31, 2004 (SNC Letter No. NL-04-1594), the applicant added aging

management for the charging/high head safety injections (HHSI) pump casings. The pump

casings are carbon steel with stainless steel clad and the intended function is pressure

boundary. The applicant identified loss of material as the aging effect (base metal corrosion

due to clad cracking), and that this aging effect will be managed by the Periodic Surveillance

and Preventive Maintenance Activities.

Aging Effects

Table 2.3.2.3 of the LRA lists individual system components for the emergency core cooling

system that are 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 charging/safety injection miniflow

orifices; encapsulation vessel; flow orifices and elements; residual heat removal heat exchanger

channel heads, tubesheets, and tubes; high-head safety injection pump oil cooler shell, channel

head, and tubes; piping; high-head and residual heat removal pump casings; safety injection

accumulators; refueling water storage tank; valve bodies; and vortex breakers.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Stainless steel and stainless steel clad components exposed to a borated water

environment are subject to the aging effect of loss of material.

* Stainless steel residual heat removal heat exchanger tubes exposed to a closed-cycle

cooling water (CCCW) environment are subject to the aging effect of cracking.

* Copper high-head safety injection oil cooler tubes exposed to a CCCW environment are

subject to the aging effect of loss of material.

* Carbon steel components exposed to an air/gas environment are subject to the aging

effect of loss of material.

* Carbon steel components exposed to a dry gas environment experience no aging

effects.

* Stainless steel components exposed to air/gas, dry gas, embedded, inside, and outside

environments experience no aging effects.

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I

* Carbon steel and copper alloy components exposed to a lube oil environment

experience no aging effects.

* 'Carbon steel with stainless steel clad pump casings exposed to a borated water

environment are subject to loss of material (base metal corrosion due to clad cracking).

'h-- -

* Cast iron high-head safety injection oil cooler channel heads exposed to aCCCW

environment are subject to the aging effect of loss of material. - -.. )- - . '' -.-. 

During its review,'the staff determined that it needed additional information to complete its ',

evaluation of the emergency core cooling system. Section 3.2.2.3.4.1 of this SER contains the

staff's evaluation of the loss of material for stainless steel and stainless steel clad components

-in a borated water environment. Section 3.2.2.3.4.2 of this SER contains the staff's evaluation

of the loss of preload and cracking'for closure bolting.

Table 3.2.2-3 of the LRA states that the applicant did not determine the loss of material in an oil

environment to be an AERM for the carbon steel oil cooler shell and the copper alloy tubes for

the high-head safety injection pump in the emergency core cooling system. 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. In RA1 3.2-2,- the staff asked the applicant to justify not managing the aging effect

of the loss of material due'to general, pitting, and crevice corrosion and MIC for the high-head

safety injection pump components. In its response dated March 5, 2004, the applicant stated

that the lubricating oil systems are typically closed systems, and tube failure is not assumed

because the cooling water side of the tubes is managed for aging. Therefore, the lubricating oil

is assumed to be free of water contamination. Significant corrosion is only expected where

water can settle or pool. Sirice water cbnta'mination is not expected, settling or pooling should

not occur; therefore, the lubricating oil systems are not susceptible to the lossof material due to

general, pitting, and crevice corrosion or MIC. The applicant stated that its 'operating -

experience supports this conclusion. Although not credited for license renewal, the operators

visually check the oil levels for the high safety injection/charging pumps every shift for the

proper level and visual evidence of contaminations The oil is sampled every 6 months and is

changed based on the'results of the sampleianalysis. The applicant also checks the oil levels

and conditions during quarterly pump surveillance testing. Based on the applicant's response

that water settling'or pooling is not expedted,'and -bcause the operating experience at FNP

supports this conclusion,'the staffconcsiii that the loss of material in the lubricating oil coolers

is not an AERM. I; - ;-; - -

In RAI 3.2-3, the staff asked the applicant if it 6onisidered selective leaching to be an aging ;

mechanism for the 'coppeF alloy oil cooler tubes'for the high-head safety injection pump. In its

response dated March-5, 2004, theapplicant stated that it did not consider the oil cooler tubes

to be susceptible to6selective leaching. These tubes are fabricated from admiralty brass, which

inhibits or incr&e'asesresistance'to'selective'leaching. i In the nonaggressive lubricating oil and

CCCW environment,'selective leaching is not expected to be a significant degradation -

mechanism for admiralty brass. The aging mechanisms for the oil cooler tubes are pitting,

crevice corrosion, and MIC, which are managed by the Water Chemistry Control Program and

the One-Time Inspection Program, as identified in LRA Table 3.2.2-3. Based on the applicant's

response, the staff concurs that selective leaching is not an AERM for the high-head safety

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injection pump oil cooler tubes.

In RAI 3.2-5, the staff requested the applicant to justify its use of the One-Time Inspection

Program to manage the loss of material for the carbon steel encapsulation vessel in an air/gas

(wetted) environment. Section 3.0.4 of the LRA defines an air/gas (wetted) environment as

containing significant amounts of moisture where condensation or water pooling may occur. In

its response dated March 5, 2004, the applicant stated that LRA Table 3.2.2-3 incorrectly shows

the internal environment of the encapsulation vessel. The correct internal environment is

air/gas, which is defined as containing air that is similar in temperature and moisture content to

ambient air conditions located throughout the plant, with no significant condensation, expected.

The internal air/gas and gas environment of the encapsulation vessel is stagnant and at the

same temperature as the surroundings, such that condensation is not expected. Thus, no

significant amounts of moisture are available where condensation or water pooling could occur.

Based on the applicant's response, the staff considers the One-Time Inspection Program

acceptable to manage the loss of material for the carbon steel encapsulation vessel in an

'air/gas environment.

Table 3.2.2-3 of the LRA lists the loss of material and cracking, but not erosion, as AERMs for

the flow orifice/element. In RAI 3.2-6, the staff requested the applicant to describe the flow

orifice/element, its location in'the system, and why it did not consider erosion to be an AERM.

In its response dated March 5,-2004, the applicant stated that FNP uses the stainless steel flatplate orifices for both flow measurement and flow restriction, and the orifices do not experience

significant pressure drops. These plates are located in various locations, such as downstream

of the high-pressure coolant injection pumps for flow instrumentation. Revision 3 to EPRI

TR-1003056, uNon-Class 1 Mechanical Implementation Guideline and Mechanical Tools," -

issued November 2001, states the following:,

Material loss because of erosion is possible only if the fluid contains particulates in the fluid stream

that impinges upon the surface of the 'metal. Treated water chemistry and filtration' requirements typically preclude the buildup of particulates that could contribute to abrasive erosion of carbon

steel, low-alloy, wrought austeniti stainless steel, cast iron, CASS, copper alloys, and nickelbased alloys.

Stainless steel materials are not generally susceptible to any form of erosion, erosion-corrosion,

or FAC in a borated water environment: Even without chemistry controls, the closed nature of

the system and the tightly adherent oxide layers formed by these austenitic materials preclude

the possibility of any significant erosion of the material. Therefore, FNP does not consider.

erosion of these stainless steel flat-plate orifices an AERM. Based on the applicant's response,

the staff does not consider erosion an AERM for the stainless steel flat-plate orifices.

On the basis of its review of the LRA, the staff finds the aging effects of, the emergency core

cooling system component types given above that are not addressed by the GALL Report are

consistent with industry experience for these material-environment combinations. The staff did

not identify any omitted aging effects for the combinations in LRA Table 3.2.2-3. using notes F

through J. Therefore, the staff finds that the applicant has identified the appropriate aging

effects for the materials and environments associated with the above components in the

emergency core cooling system.

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Aging Management Programs '

After evalu'ating the-applicant's identification of agirig effects for each of the above compnonents,

staff evaluated the Sthe AMPs todete'rriineif they~are appropriate for managing the identified

aging effects. The staff also deterrmined that the FSAR Supplement adequately describes the

program. :- 'C ,.

Table 3.3.2-3 of the LRA identifies the following AMPs for managing the aging effects described

above for the emergency core cooling system:

Water Chemistry Control Program"(LRA Section B.3.2)

* One-Time Inspection Program (LRA 'Section'B15.5) - Periodic Surveillance and Preventive Maintenance Activities (LRA Section B.5.9)- 4 . ,.-,--A* .w.- --.. A '' *-- 

Sections 3.0.3.2.1, 3.0.3.1, and 3.0.3.3.4, respectively, of this SER provide the staff's review of

theseAMPs;. -:

On the basis of its r6view'of the'LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the emergency core cooling system component types

that are not addressed by the GALL Report. In addition, the staff finds the program descriptions in the FSAR Supplement acceptable. '

j ~ ~ - ~ ~ i.. -. .

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the emergency core

cooling system components that are not addressed by the GALL Report, so that the' intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 51.2i(a)(3). '

The staff also reviewed the applicable FSAR Supplem ent program descriptions and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by lOCFR 54.21(d).''

3.2.2.3.4 Generic Issues for the Engineered Safety Features ;

3.2.2.3.4.1 Stainless Steel Components in Borated Water Environment. In RAI 3.2-4, the staff

requested the applicant to explain why it will not perform a' one-time inspection to determine the

effectiveness of the Water Chemistry Control Program for stainless steel components in a

borated water environment.- In its response dated March 5, 2004, the applicant stated that

localized corrosion of stainl6ss steels is not a lorig-term, linearly progressive process like

general corrosion of carbon steels. 'Stainless steels derive their corrosion r6sistance from the

thin, tightly adherent, passive chromium 6xide layer that forms at the'components' surface. If

the environmental conditions are not sufficiently aggressive to penetrate this oxide layer, then

no significant 6oii6sioinis expected tofresult. For austenitic stainless steels, -penetration of the

passive chromium oxide layer and subsequent corrosion has bee'n shown to be related

principally to the oxidizing nature of the environment and the presence of specific detrimental

ionic species know to interfere with the passivation process, most notably chlorides, sulfates,

and fluorides: According to EPRI TR-1 003056, localized corrosion of stainless steels exposed

3-157
to borated water is not a significant concern when dissolved oxygen concentrations are less

than 100 ppb and concentrations of detrimental ionic species are less than 150 ppb. The FNP

Water. Chemistry Control Program limits both dissolved oxygen and detrimental ionic species -

concentrations to values well below those specified by these limits. Experience both at FNP

and throughout the industry confirm that pitting and crevice corrosion have not been an issue of

concern for these materials and environments. Based on the applicant's response, the Water

Chemistry Control Program is acceptable to manage the aging effects for stainless steel

components in a borated water environment.

3.2.2.3.4.2 Cracking and Loss of Preload for Bolting Components. The GALL bolting Integrity

program, described in Section XI-Ml 8, addresses the aging effects of cracking and loss of

preload (stress relaxation) for closure bolting. Cracking is considered an AERM for carbon and

alloy steel bolts with an actual yield strength for the material that is equal to or greater than 150

ksi. Stress relaxation is considered an AERM for bolts in a high-temperature environment.

Tables 3.2.2, 3.3.2, and 3.4.2 of the LRA do not address cracking or stress relaxation for these

conditions. In RAI 3.2-7 dated April 8, 2004, the staff asked the applicant if any bolting in the

engineered safety features, auxiliary systems, or steam and power conversion systems require

aging management for the aging effects of cracking and loss of preload (stress relaxation). In

its response dated May 5, 2004, the applicant stated the following:

The aging management reviews for the engineered safety features (ESF), auxiliary, and steam and

power conversion (S&PC) systems at FNP determined that cracking of high strength bolting and

loss of preload due to stress relaxation of bolting are not aging effects requiring management at

FNP and no aging management program needs to be credited. The mechanism of concern for

cracking for high strength bolts is stress corrosion cracking (SCC). The bases for these

conclusions are outlined below.

SCC of High Strength Boltin --

For the ESF, auxiliary, and S&PC systems, the bolts identified as having the potential for an actual

yield strength that may be equal to or greater than 150 ksi are ASME SA-193/ASTM A193

Grade B7 bolts. These bolts have a minimum specified yield strength of 105 ksi, however no

maximum yield strength is specified for this material. Therefore, the actual yield strength for these

bolts could exceed 150 ksi -

Although there have been isolated instances of SCC of bolting in the industry, these failures have

been attributed primarily to high yield stress materials (including abnormally high'yield stresses

resulting from improper heat treatment), excessive bolt preload, and contaminants, such as the

use of thread lubricants containing molybdenum sulfide (MoS2).' 'A review of industry failure

databases and NRC generic communications supports the fact that a combination of material

selection, control of contaminants, and proper maintenance and torquing procedures is effective in

eliminating the potential for SCC of bolting materials. These practices are in place at FNP as

discussed below.

Material Selection-EPRI NP-5769, 'Degradation of Bolting in Nuclear Power Plants," April 1988

indicates that susceptibility to SCC is minimized through selection of materials having specified

minimum yield strengths less than 150 ksi. The ESF, auxiliary and S&PC systems bolting

materials meet this criteria. ASME SA-193/ASTM A193 Grade B7 bolts have a minimum specified

yield strength of 105 ksi, which is below the recommended value of 150 ksi.

Control of Contaminants-In general, environmental conditions that could lead to SCC of bolting

are not expected to occur in non-Class 1 components. Most bolting at FNP is normally in a dry

,, environment and oated with a lubricant. For bolting located outdoors, the atmosphere is mild in

terms of corrosive contaminants (rural environment and remote from coastal regions). Rain tends

to wash off contaminants instead of concentrating them. Within the industry, SCC failures of

quenched and tempered alloy steel bolting, such as SA-193 Grade B7 bolts, have many times

3-158
been associated with the use of lubricants that may decompose into SCC-inducing contaminants,

most notably MoS2. FNP has not used lubricants containing MoS2 and procedural controls are in

place at FNP to prevent the use of lubricants containing potentially detrimental species such as

chlorides and sulfates. -

Control of Bolt Preload-Excessive bolt stresses have resulted in SCC failures in'the industry.

Proper control of bolt preload through sound bolt tdrquing practices has been shown to prevent

excessive preload and thereby minimize the potential for SCC failures. At FNP, procedural

controls are in place to assure that proper bolt torquing practices are used.

The potential for SCC of bolting materials has been addressed at FNP in response to several

industry communications including NRC IE Bulletin 82-02, INPO SOER 84-5, and EPRI guidance

documents. The bolting materials usedjiubricantlcontaminant controls, and sound bolt torquing

practices have been effective at eliminating this aging effect. A review of recent FNP operating

history performed for development of the FNP LRA did not identify any instances of SCC in

engineered safety features systems, auxiliary systems, and steam and power conversion systems

bolting which includes ASTM SA-1 93/ASTM Al 93 Grade B7 fasteners. Additionally, a review of

recent NRC generic commriunications dlid not identify any recent bolting failures attributable to SCC.

Therefore, cracking due to SCC is not an aging effect requiring management for the carbon steel

and alloy steel bolting materials used in FNP engineered safety features systems, auxiliary

systems, and steam and power conversion systems.

Loss of Preload Due to Stress Relaxation of Bolting Materials

SNC has determined that loss of preload (stress relaxation) in bolted connections is not an aging

effect requiring management for the engineered safety features systems, auxiliary systems, and

steam and power conversion systems at FNP.

Work performed as a part of the EPRI Material Reliability Program indicates that secondary,

steady-state, creep only occurs for alloy steels when operating temperatures exceed 40% to 50%

of the melting temperature (in absolute units). A conservative lower bound melting temperature for

steel bolting materials Is 2500 0F (2959 0

R). Accordingly, SNC concludes that no steady-state

creep of bolting will occur at operating temperatures below 725 "F. The FNP operating

temperatures in the engineered safety features systems, auxiliary systems, and steam and power

conversion systems are below this threshold temperature.

Leakage at joints is typically associated with improper joint installation (e.g., proper cleanliness,

gasketing, and preload) or inadequate joint design, not relaxation of the bolting materials. FNP

procedures for joint installation incorporate Industry guidance from EPRI NP-5769, Good Bolting

Practices, and EPRI TR-l 04213, Bolted Joint Maintenance and Application Guide. These

procedures provide for the use of proper lubricants and sound bolt torquing practices. However,

these procedures are considered to be a part of normal maintenance practices and are not

credited as a specific aging management program for license renewal. -

Lastly, FNP operating experience has not Indicated any problems with loss of preload due to

stress relaxation in bolted closures.

Based on this information, SNC maintains that loss of preload due to stress relaxation is not an

aging effect requiring management for bolted connections in the engineered safety features

systems, auxiliary systems, and steam and power conversion systems at FNP.

The staff considers the applicant's response satisfactory to address SCC for high-strength bolts

and loss of preload due to stress relaxation for the engineered safety feature, steam and power

conversion, and auxiliary systems. High-strength bolts do'not require aging management for'

SCC, based on bolting material selectiorn and industry bolting practices. Theloss of preload

due to stress relaxation does not require aging management based on system operating

temperatures and industry bolting practices.

3-159
II

3.2.3 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that the

aging effects associated with the engineered safety feature systems components will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging of the

engineered safety feature systems, as required by 10 CFR 54.21 (d).

3.3 Aging Manaaement of Auxiliary Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

auxiliary system components and component groups associated with the following systems:

* new fuel storage

* spent fuel storage

* spent fuel pool cooling and cleanup

* overhead heavy and refueling load handling

* open-cycle cooling water

* closed-cycle cooling water

* compressed air

* chemical and volume control

* control room area ventilation

* auxiliary and radwaste area ventilation

* primary containment ventilation

* yard structures ventilation

* fire protection

* diesel fuel oil

* emergency diesel generator

* demineralized water

* high-energy line break detection

* hydrogen control

* liquid waste and drains

* oil-static cable pressurization

* potable and sanitary water

* radiation monitoring

* reactor makeup water storage

* sampling

3.3.1 Summary of Technical Information in the Application

In LRA Table 3.3.1, "Summary of the Aging Management Evaluations for Auxiliary Systems in

Chapter VIl of NUREG-1801," thie applicant provided a summary comparison of its AMRs with

the AMRs evaluated in the GALL Report for the auxiliary system components and component

groups that are relied on for license renewal.

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I

The applicant's AMRs incorporated opierating experience applicable to the determination of

AERMs. -These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of condition reports and discussions with

appropriate site personnel to identify AERMs. JThe applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report in 2001.

The applicant conducts its ongoing review of plant-specific and industry operating experience

in accordance with the FNP, Units 1 and 2, Operating Experience Program.

3.3.2 Staff Evaluation

'The staff reviewed Section 3.3 of the LRA to determine if the applicant had provided sufficient

information to demonstrate that the effects of aging on the auxiliary system components that

are within the scope of license renewal and subject to an AMR will be adequately mahaged, so

that the intended furnctions 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 confirrnthe applicant's claim that certain identified

AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report. However, the staff did determine that the material presented in

the LRA was applicable and that the applicant had identified the appropriate GALL Report:

AMPs. The staff documented its evaluations of the AMPs in Section 3.0.3 of this SER. The

FNP Audit and Review Report provides details of the staff's audit and review for these AMRs.

The staff also performed an audit and review-of those AMRs that were consistent with the GALL

Report and for which GALL recomm6nds further evaluation. During the audit, the staff

determined that the applicant's additional evaluations were consistent with the acceptance

criteria in Section 3.3.2.2 of the SRP-LR. The FNP Audit and Review Report, as summarized in

Section 3.3.2.2 of this SER, details the staff's audit and review of these AMRs.

The staff conducted a technical review of the remaining AMRs that were not consistent with the

GALL Report. The review included evaluating whether the applicant identified all plausible

aging effects that were appropriate for the material-environment combinations specified.

Section 3.3.2.3 of this SER documents the details ofthe s r and evaluation for these

AMRs that are not consistent with the GALL Report. ' -

Finally, the staff reviewed the AMP summaries in the FSAR Supplement to ensure that they

adequately describe the programs credited with managing or monitoring aging for the reactor

system components.

Table 3.3-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in Section 3.3 of the LRA that are addressed in the GALL Report.

3-1 61
aI

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

- I ';, . i " I -. - ., . , ~ - -- - !. , 'n ,t - In -_ . rConpo'nent up' . AgIng Effectl:§? :AMP In GALL fi t AP In i *'-- fflEiluatoh'-

Components in Loss of material Water chemistry None Consistent with

spent fuel pool due to general, and one-time GALL, which

cooling and cleanup pitting, and crevice inspection recommends further

Item Number corrosion evaluation. (See

3.3.1-1 Section 3.3.2.2.1)

Linings in spent fuel Hardening, Plant specific Extemal Surfaces Consistent with

pool cooling and cracking, and loss Monitoring Program GALL, which

cleanup system; of strength due to (Appendix B.5.3) recommends further

seals and collars in elastomer - evaluation. (See

ventilation systems degradation; loss of Section 3.3.2.2.2)

Item Number material due to

3.3.1-2 wear

Components in load Cumulative fatigue TLAA, evaluated 10 CFR 54.21(c)(1)(i) Consistent with

handling, chemical damage in accordance with analyses remain valid GALL, which

and volume control 10 CFR 54.21(c) recommends further

system (PWR), and evaluation. (See

reactor water Section 3.3.2.2.3) cleanup and

shutdown cooling

systems (older BWR)

Item Number

3.3.1-3

Heat exchangers in Crack initiation and Plant specific Water Chemistry Consistent with

reactor water growth due to SCC Control Program GALL, which

cleanup system or cracking (Appendix B.3.2) recommends further

(BWR); high- evaluation. (See

pressure pumps in Section 3.3.2.2.4) chemical and

volume control

system (PWR)

Item Number

3.3.1-4 .

Components in Loss of material Plant specific One-Time Inspection Consistent with

ventilation system, due to general, Program (Appendix GALL, which

diesel fuel oil pitting, and crevice B.5.5); recommends further

system, and corrosion, and MIC Extemal Surfaces evaluation. (See

emergency diesel Monitoring Program Section 3.3.2.2.5)

generator systems; (Appendix B.5.3) external surfaces of

carbon steel

components

Item Number

3.3.1-5

3-162
F F F Y

Cornionint Grottop' I. - ~ _1 1'1

 - u'111  - "

1. - -!AgIn4 Eff6cU'-'--- -- ,; - ;- -..L. I -.Mechinlsm-i-,i- - aMp iart ~ ~ nLA' 'I 'tf vjaJn

Components In Loss of material One-time - One-Time Inspection Consistent with -

reactor coolant due to galvanic, inspection - Program (Appendix GALL, which

pump oil collection general, pitting, and B.5.5) recommends further

system of fire crevice corrosion evaluation. (See

protection" Section 3.3.2.2.6)

Item Number *

3.3.1-6

Diesel fuel oil tanks Loss of material Fuel oil chemistry Fuel Oil Chemistry Consistent with

in diesel fuel oil due to general, and one-time Control Program GALL, which

system and " pitting,'and crevice inspection (Appendix B.4.2); recommends further

emergency diesel corrosion, MIC, and One-Time - evaluation. (See

generator system biofouling Inspection Program Section 3.3.2.2.7)

Item Number (Appendix B.5.5)

3.3.1-7 ;

Heat exchangers in I Crack initiation and Water chemistry Water Chemistry Consistent with

chemical and growth due to SCC and a plant- Control - - GALL, which -

volume control and cyclic loading specific Program (Appendix recommends further

system verification 6.3.2) evaluation. (See

Item Number program Section 3.3.2.2.9)

3.3.1-9

Ne'utron-absor'bing'- Reduction of 'Plant specific None - . Consistent with -

sheets in spent fuel: neutron-absorbing -. GALL, which

storage racks capacity and loss of , recommends further

Item Number material due to ' evaluation. (See

3.3.1-10 ' general corrosion Section 3.3.2.2.10)?

(boral. boron steel) .

New fuel rack Loss of material Structures Structural Monitoring- Consistent with

assembly' due to general, monitoring - Program (Appendix GALL; which --

Item Number pitting, and crevice -- B.4.3) - ' recommends no

3.3.1-11 corrosion further evaluation.

(See Section

_ _3.3.2.1)

Neutron-absorbing Reduction of Boraflex None Consistent with

sheets In spent fuel, neutron-absorbing monitoring GALL, which

storage racks capability due to recommends no

Item Number Boraflex further evaluation.

3.3.1-12 degradation (See Section

3.3.2.1)

Spent fuel storage Crack Initiation and Water chemistry - Water Chemistry Consistent with -

racks and valves In growth due to stress ' Control Program GALL, which

spent fuel pool corrosion cracking (Appendix B.3.2)-; recommends no'

cooling and cleanup further evaluation.

Item Number (See Section

3.3.1-13 ____ 3.3.2.1) ; -

'3-163
I - a

I

.. .. ... A AMPIn LIFA~~'1. -4 _'Staff EVaiatlo, C' mponent`Group.z ; Aging EffcV, -GAi

Closure bolting and Loss of material Boric acid Borated Water Consistent with

external surfaces of due to boric acid corrosion Leakage Assessment GALL, which .

carbon steel and corrosion and Evaluation recommends no

low-alloy steel Program (Appendix further evaluation.

components B.3.5) (See Section

Item Number 3.3.2.1)

3.3.1-14

Components in or Loss of material Closed cycle Water Chemistry Consistent with

serviced by closed due to general, cooling waster Control Program GALL, which

cycle cooling waster pitting, and crevice system (Appendix B.3.2); recommends no

system corrosion, and MIC One-Time Inspection further evaluation.

Item Number Program (Appendix (See Section

3.3.1-15 B.5.5) 3.3.2.1)

Cranes including Loss of material Overhead heavy Structural Monitoring Consistent with

bridge and trolleys due to general load and light load Program (Appendix GALL, which

and rail system in corrosion and wear handling systems B.4.3); recommends no

load-handling Overhead and further evaluation.

system Refueling Crane (See Section

Item Number Inspection 3.3.2.1)

3.3.1-16 Program (Appendix B.3.6 )

Components in or Loss of material Open cycle Service Water Consistent with

serviced by open : due to general, cooling waster Program (Appendix GALL, which

cycle cooling waster pitting, crevice, and system B.4.4) recommends no

systems galvanic corrosion, further evaluation.

Item Number MIC, and biofouling; (See Section

3.3.1-17 buildup of deposits 3.3.2.1)

due to biofouling

Buried piping and Loss of material Buried piping and Buried Piping Consistent with

fittings due to general, tanks surveillance and Tank Inspection GALL. which

Item Number pitting, and crevice Program (Appendix recommends no

3.3.1-18 corrosion, and MIC or B.5.4) further evaluation.

(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 in Loss of material Compressed air One-Time Inspection Consistent with

compressed air due to general and monitoring Program (Appendix GALL, which

system pitting corrosion B.5.5) recommends no

Item Number further evaluation.

3.3.1-19 (See Section _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 3 .3 .2 .1 )

3-164
Coponient Fo~ up ln 44fetIK . ln~iGALV,% _u6t -SIti fAMPa 6f

Components (doors Loss of material Fire protection Fire Protection Consistent with

and barrier due to wear ; - - Program (Appendix GALL, which

penetration seals) hardening and '3.4.5); Structural. recommends no

and concrete shrinkage due to Monitoring Program further evaluation.,

structures in fire weathering (Appendix B.5.5) (See Section

protection - 3.3.2.1)

Item Number

3.3.1-20

Components in Loss of material Fire water system Fire Protection - Consistent with

water-based fire due to general, Program (Appendix GALL, which

protection. pitting, crevice, and B.4.5); One-Time recommends no

Item Number galvanic corrosion, - Inspection Program further evaluation.

3.3.1-21 MIC, and biofouling (Appendix B.5.5) (See Section

- ,3.3.2.1)

Components In Loss of material Fire protection- Fire Protection Consistent with

diesel fire system due'to'galvanic, and fuel oil - Program (Appendix GALL, which

Item Number general, pitting, and chemistry -;. B.4.5); Fuel Oil -recommends no

3.3.1-22 crevice corrosion , Chemistry Control further evaluation.

Program (Appendix (See Section

B.4.2) 3.3.2.1) ;- .

Tanks in diesel fuel Loss of material Aboveground External Surfaces Consistent with.

oil system - due to general, carbon steel tanks Monitoring Program GALL,'which

Item Number pitting, and crevice (Appendix B.5.3) recommends no

3.3.1-23 corrosion further evaluation.

(See Section

,_ ;.: 3.3.2.1)

Closure bolting Loss of material Bolting integrity Extemal Surfaces Consistent with

Item Number due to general Monitoring Program GALL, which

3.3.1-24 corrosion; crack (Appendix B.5.3) -recommends no.

initiation and growth further evaluation.

due to cyclic , (See Section

loading and SCC . 3.3.2.1)-

Components Loss of material Selective leaching Water Chemistry Consistent with

(aluminum bronze, due to selective of materials Control Program GALL, which

brass, cast iron, leaching (Appendix B.3.2); recommends no

cast steel) in open One-Time Inspection further evaluation.

cycle cooling waster - : Program (Appendix -*- (See Section

and closed cycle B.5.5) 3.3.2.1)

cooling waster

systems, and

ultimate heat sink

Item Number -'

3.3.1-29 *

3-165
N

pComponenAGroup Aing Effe . n G ALLRAMfi jA in L '-

,________________ Me-chan-sm;-ffi>-k[ 2Report-i '. I I.-, : h;

Fire barriers, walls, Concrete cracking Fire protection Structural Monitoring Consistent with

ceilings, and floors and spalling due to *and structures Program (Appendix GALL, which

in fire protection freeze-thaw, monitoring 8.4.3) recommends no

Item Number aggressive' further evaluation.

3.3.1-30 chemical attack, (See Section

and reaction with 3.3.2.1)

aggregates; loss of

material due to

corrosion of

embedded steel

The staff's review of the applicant's auxiliary system and associated components follows

several approaches. One approach, documented in Section 3.3.2.1, involves the staff's review

of the AMR results for components in the auxiliary system and associated components 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, involves the staff's review of the AMR

results for components, in the auxiliary system and associated components that the applicant

indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in Section 3.3.2.3, involves the staff's review of

the AMR results for components in the auxiliary system and associated components 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 system components.

3.3.2.1 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Not Recommended

Summary of Technical Information

In Sections 3.3.2.1.1 through 3.3.2.1.24 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 system components:

* Water Chemistry Control Program

* Borated Water Leakage Assessment and Evaluation Program

* One-Time Inspection Program

* External Surfaces Monitoring Program

* Structural Monitoring Program

* Overhead and Refueling Crane Inspection Program

* Service Water Program

* Buried Piping and Tank Inspection Program

* Fire Protection Program

* Fuel Oil Chemistry Control Program

Staff Evaluation

In Tables 3.3.2-1 through 3.3.2-24 of the LRA, the applicant summarized the AMRs for the

3-166
auxiliary 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 io deterrimine whether the plant-specific components.

contained in these GALL Report component groups 'were bounded by the GALL Report

evaluation. The staff also identified several areas heeding additional information or clarification.

The staff's evaluation of the applicant's' responises'an'd clarification appears below.-

3.3.2.1.1 Loss of Material Due to Selective Leaching (Table 3.3.1, Line Item 3.3.1-29)

Column 8 of Table 2 (LRA Tables 3.3.2-x) refer'red to Item 3.3.1-29 of Table 1 for many

auxiliary system components with the loss' of material aging effects due to selective leaching of

carbon steel, copper alloy (brass), and stainless steel materials. The discussion column of -

Table 1,'Item` 3.3.1-29, addressed only CCW pumpssfabricated frobn carbon steel. The staff

issued RAI 3.3-4 requesting that the applicant provide'additio'nal information on how it

addressed selective leaching aging'mechanisrns` for~copper alloy (brass) and stainless steel ,

mat6rials in the components of the [uxilia'rsysterms.- :The staff also asked the applicant to - --

describe the program credited with detecting the selective leaching of materials and compare it

with the GALL AMP X.M33, uSelective Leaching of Materials," for consistency determination.

By letter dated March 5, 2004, the applicant responded to RAI 3.3-4. In its response, the

applicant stated that there are inconsistencies in referencing (LRA Table 3.3.2-x to "Table 1

Item" 3.3.1-29 in Column 8) for carbon steel and stainless steel components. Carbon steel and

stainless steel are not susceptible to electiv6 leaching in the auxiliary system environments. -

The inconsistency was a result of the way ihe GALL Report is structured and how the

information from the GALL Report was transferred to' the LRA:

For example, Table 3;3.2-5 of the LRA listed the CCW heat exchanger (shell)'line item as

having a material of carbon steel; an interrnal envir6nment of closed-cooling water, and an

AERM of loss of material. This matches with the GALL Report, Volume 2, Chapter VII,

IteriC1.3-a, which includes carbon steel, aluminum-bronze, copper-nickel, and aluminum brass

materials.' Theaipplicant also provided a table su mmarizing the components in the Table 3.3.2-

x tables which are potentially susceptible to the loss of material due to selective leaching. The

staff reviewed the applicant's response and confirmed that these inconsistencies had been

corrected.

The applicant credited the One-Time Ispecti6'n Program (AMP-B.5.5) for detection-of selective

leaching irilpotentially susceptible materials.';

Section 3.0.3.1 of this SER documents thfestaff's'review of the One-Time Inspection Program

In its evaluation, the staff concludes that this program is consistent with GALL-AMP XI.M33 for

the detection of selective leaching.

The staff concludes that, based on the preceding discussion, the applicant has appropriately

identified the components that are'susceptible'to'the loss of material due to selective leaching

and adequately described the-AMP credited with managing these effects. -

-3-167
I - a

3.3.2.1.2 Open-Cycle Cooling Water System (Table 3.3.2-5)

The staff reviewed Table 3.3.2-5 of the LRA which summarizes the results of the AMR

evaluations in the SRP-LR for. the auxiliary system OCCW system.

Table 3.3.2-5 of the LRA lists loss of material and fouling as aging effects for several

components requiring aging management in the OCCW system.: The staff noted that fouling is

generally an aging effect for heat transfer, not pressure boundary. The staff issued RAI 3.3-3

requesting that the applicant explain how fouling is related to the pressure boundary intended

function of these components.

By letter dated March 5, 2004, the applicant responded to RAI 3.3-3. The applicant stated that

fouling is not related to the pressure boundary intended function of the channels heads, sheets,

and tubesheets of the heat exchangers and coolers listed in Table 3.3.2-5 of the LRA.

Therefore, the applicant should not have identified it as an AERM. The applicant stated that no

other changes to Table 3.3.2-5 of the LRA result from the removal of fouling as an AERM for

these components. This is consistent with the GALL Report, Volume 2, which does not identify

fouling as an aging effect applicable to these components. The staff reviewed the applicant's

response and confirmed that fouling has been removed as an AERM for these components.

Based on its review and on the preceding discussion, the staff finds the applicant's response

acceptable.

3.3.2.1.3 Diesel Fuel Oil System (Table 3.3.2-14)

For the fuel oil storage and EDG day tanks in the fuel oil environment, the applicant, in Table

3.3.2-14 of the LRA, credited the Fuel Oil Chemistry Control Program (AMP 6.4.2) for

managing the aging effect of loss of material. ,It also referenced Table 3.3.1, Item-3.3.1-7, of

the LRA, which refers to Section 3.3.2.2.7 of the LRA for further discussion. However, Section

3.3.2.2.7 of the LRA states that the Fuel Oil Chemistry Control Program and One-Time

Inspection Program (AMP B.5.5) will manage the loss of material in the fuel oil storage and day

tanks.

The applicant indicated that this was an editorial error. Table 3.3.2-14 of the LRA should have

included the One-Time Inspection Program with the Fuel Oil Chenmistry.Control Program. By

letter dated May 28, 2004, the applicant provided its application errata to address this editorial

error. In its application errata, the applicant confirmed that for the fuel oil storage and EDG day

tanks in the fuel oil environment, the One-Time Inspection Program (in addition to the Fuel Oil

Chemistry Control Program) should be listed in the AMP column. The other table entries for the

fuel oil environment remain unchanged. The staff review of the One-Time Inspection Program

indicated that this component group is included in the scope of the One-Time Inspection

Program in Appendix B.5.5 to the LRA. Therefore, the staff concludes that Item 3.3.1-7 is

consistent with the GALL Report.

3.3.2.1.4 Emergency Diesel Generator System (Table 3.3.2-15)

Table 3.3.2-15 of the LRA defines the equipment frames and housings (crankcase ventilation)

in the EDG system as consistent with the GALL Report, Item VII.H2.4-a, for material,

environment, aging effects, and AMPs.

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The staff noted that the'GALL'Report item' is f6ra6 different component. 'The material of the

EDG equipment frames and housings in Table 3.3.2-15 of the LRA'is cast iron in a wetted air

environment. The material for Item VII.H2.4-a is carbon steel in an environment with hot diesel

engine gases containing moisture and'particulate~s' Therefore, the material and environment

for the equipment frames and housings are different from the material and environment listed in

the GALL Report, Item VII.H2.4-a.

The staff issued RAI 3.3-5 requesting the applicant to justify its conclusion that the EDG

equipment frames and housing are consistent with-the GALL Report, determine whether the

One-Time Inspection Program applies~to the'equipment frames and housings, and make any

necessary changes to the table.

By letter dated March 5, 2004, the'applicant responded to RAI 3.3-5. The applicant stated that

Section 3.0.2 of the LRA provided the aging management strategy comparison with the GALL

Report. In Section'3.0.2 of the LRA, the applicant-stated that the GALL Report line item

comparison is based fundamentally on the intent to manage aging. Section 3.0.3.4.2 of the

LRA states the following:

The aging management line item comparison is performed with the goal of illustrating the best

possible match between a Table 2 of the LRA line item and a GALL Report Volume 2 aging

management line item. The primary emphasis is placed on finding a similar aging management

strategy for the same material and environment combination. The aging management strategy

comparison is provided as a review aid only.

In addition, the applicant stated that the cast iron component type in question, "equipment

frames and housings (crankcase ventilation)," is part of the crankcase exhaust system on the

EDGs. Table 3.3.2-15 of the LRA compares the cast iron crankcase component type to the

GALL Report, Item VILIH.2.4-a, with a note'C;- Note'C indicates that the component is different

but is consistent with the GALL Report for material, environment, and aging effects, and the

AMP is consistent with the GALL AMP. The applicant agreed that the cast iron material is

technically different frormi the GALL Report item of carbon steel material and that the use of note

C causes confusion. However, the applicant provided the GALL Report comparison information

only as a review aid. The applicant stated that no'change to th'e AMR results (e.g., aging

effects and AMPs) in Table 3.3.2-15 of the LRA was required.

Based on its review of the applicant's clarification, the staff concurs that this line item is

consistent with'the GALL Report component line item selected for comparison. -

On the basis of its review, the staff determined that for AMRs not requiring further evaluation,

as identified in Table 3.3.1 of the LRA (Table 1), the applicant's references to the GALL Report

are acceptable and no further staff review is required.

Conclusion "

The staff has evaluated the applicant's 'claim of consistency with' the GALL Report. The staff -

also has reviewed iriforrmation pertaining toithe applicant's consideration of recent operating

experience and proposals for managing associated aging effects.: On the basis of its review, -

the staff finds that the applicant has demonstrated that the effects of aging for these

comporierits will be adequately managed so that their intended functions will be maintained

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It

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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

Is Recommended

Summary of Technical Information in the ApDlication

In Section 3.3.2.2 of the LRA, the applicant provided further evaluation of aging management

as recommended by the GALL Report for auxiliary systems. The applicant provided information

concerning how it will manage the following aging effects:

* loss of material due to general, pitting, and crevice corrosion

* hardening and cracking or loss of strength due to elastomer degradation or loss of

material due to wear

* cumulative fatigue damage

* crack initiation and growth due to cracking or stress-corrosion cracking

* loss of material due to general, microbiologically influenced, pitting, and crevice

corrosion

* loss of material due to general, galvanic, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion and biofouling

* quality assurance for aging management of nonsafety-related components

* crack initiation and growth due to stress-corrosion cracking and cyclic loading

* reduction of neutron-absorbing capacity and loss of material due to general corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion

Staff Evaluation

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, and for which the GALL Report recommends further

evaluation, the staff reviewed the applicant's evaluation to determine whether it adequately

addressed these issues. In addition, the staff audited the applicant's additional evaluations

against the criteria contained in Section 3.3.2.2 of the SRP-LR. The FNP Audit and Review

Report contains details of these staff activities.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections.

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3.3.2.2.1 Loss of Material Due to Genreral, Pitting, and Crevice Corrosion

In Section 3.3.2.2.1 of the LRA, the applicant addressed the loss of material in components of

the spent fuel pool system.

Section 3.3.2.2.1 of the SRP-LR states that the loss of material due to general, pitting, and

crevice corrosion could occur in the channel head -and access cover, tubes, and tubesheets of

the heat exchanger in the spent fuel pool cooling and cleanup system.- The SRP-LR also states

that the loss of material due'to pitting and crevice corrosion could occur in the filter housing,

valve' bodies, and nozzles of the ion exchanger in the spent fuel pool cooling and cleanup

system' The Water Chemistry Control Progra'm relies on monitoring and control of reactor

water chemistry based on EPRI TR-1 05714 guidelines for primary water chemistry in PWRs

and EPRI TR-1 02134 for secondary water-chemistry in PWRs to manage the effects of loss of

material from general, pitting, or crevice corrosion. However, high concentrations of impurities

at crevices and locations of stagnant flow conditions could cause general, pitting, or crevice

corrosion. Therefore, applicants should verify the effectiveness of the chemistry control

program to ensure that corrosion is not occurring.tThe GALL Report recommends further

evaluation of programs to manage loss of material from general,' pitting, and crevice corrosion

to verify the effectiveness of the Water Chemistry Control Program. A one-time inspection of

select components at susceptible locations'is an acceptable method to ensure that corrosion is

not occurring and that the component's intended function will be maintained during the period of

extended operation. No loss of rmiaterial aging effects are observed for stainless steel

components exposed to air. The GALL Report lists the material for this system as carbon steel

with elastomer lining.

The applicant stated that it uses stainless steel material for this system; therefore, this aging

effect is not applicable to FNP. .The'staff concurs with this conclusion. -

3.3.2.2.2 Hardening and Cracking or Loss of Strength'Due to Elastomer Degradation or Loss

of Material Due to Wear

In Section 3.3.2.2.2 of the LRA, the applicant addressed the potential for degradation of

elastomers in collars and seals in spent fuel pool cooling and ventilation systems.

Section 3.3.2.2.2 of the SRP-LR states that hardening and cracking due to elastomer.,

degradation could occur in elastomer linings of the filter, valve, and ion exchangers in spent fuel

pool cooling and cleanup systems. Hardening and loss of strength due to elastomer

degradation could occur in the collars and seals of the duct and in the elastomer seals of the

filters in the control room area, auxiliary and radwaste area, and primary containment heating

and 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 that

these aging effects are adequately managed. - -

In Table 3.3.2-9 of the LRA, for component type Icompressible joints and seals," the applicant

credited the One-Time Inspection Program (AMP. B.5.5) with managing the aging effects of

change in material properties and loss of material. 'It also referenced Summary-Table 1 of the

LRA, item 3.3.1-2, Which referred to Section 3.3.2.2.2 of the LRA for further discussion.

However, in Section 3.3.2.2.2 of the LRA,-the applicant stated that the External Surfaces

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. I In 

Monitoring Program will manage the applicable aging effects for this component type. The staff

noted that it is not clear which AMP is credited. During a telephone conference on April 26,

2004, the staff requested that the applicant revise its response to RAI 3.3-6 to clarify which

AMP is credited.

In its letter dated May 28, 2004, the applicant provided its revised response to RAI 3.3-6 and

stated that it had revised the aging management strategy to credit the AMP B.5.3, "External

Surfaces Monitoring Program," to periodically inspect these elastomer seals and collars in

ventilation systems in lieu of the One-Time Inspection Program. The applicant concluded that

while significant aging of elastomer components is not expected to result from this potential

aging mechanism, the applicant will include the flexible connectors and floor drain plug

elastomer components in the scope of the External Surfaces Monitoring Program (in lieu of the

One-Time Inspection Program). The applicant stated that the External Surfaces Monitoring

Program will provide for periodic inspection of the elastomer components and will ensure their

continued ability to perform their intended functions.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of hardening and cracking or loss of strength due to elastorner

degradation or loss of material due to wear, 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 the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.3 Cumulative Fatigue Damage

As stated in the SRP-LR, fatigue is a TLAA as defined in 10 CFR 54.3. The TLAAs are

required to be evaluated in accordance with 10 CFR 54.21 (c)(1). Section 4.3 of this SER

documents the staff's review of the applicant's evaluation of this TLAA. In performing this

review, the staff followed the guidance in Section 4.3 of the SRP-LR.

3.3.2.2.4 Crack Initiation and Growth due to Cracking or Stress-Corrosion Cracking

In Section 3.3.2.2.4 of the LRA, the applicant addressed the potential for cracking in the highhead pumps of the chemical and volume control system.

Section 3.3.2.2.4 of the SRP-LR addresses crack initiation and growth due to cracking in the

high-pressure pumps of the chemical and volume control system. The GALL Report

recommends further evaluation to ensure that these aging effects are adequately managed.

The applicant stated in a supplemental letter dated August 31, 2004, that its high head pumps

are centrifugal pumps normally used for chemical and volume control, and are shared with the

emergency core cooling system. The aging management review results are included with the

emergency cooling system results in LRA Table 3.2.2-3. These high-head pump casings are

carbon steel with internal surfaces clad with austenitic stainless steel. The applicant indicated

that the aging effect requiring management for the borated water environment is loss of.

material due to localized corrosion. In addition, the normal operating temperature of these

pumps is below the 140 OF threshold for SCC. The applicant credited the Water Chemistry

Control Program (AMP B.3.2) for managing loss of material in the stainless steel cladding in

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these pump casings and 'the Periodic Surveillance and Preventive Maintenance Activities (AMP

B.5.9) for managing loss of material in the carbon steel base metal due to boric acid corrosion

resulting from clad cracking '(re., IN 94-63 and IN 80-38.) ,: , . : ..- : . , ' , .-. . '! ,;, , .- , - ' - '

The staff reviewed the Water Chemistry Control Program (AMP B.3.2) and concluded that this

program is adequate to manage the loss of material in the stainless steel cladding due to

localized corrosion for the b6rated water environment. Also, the staff reviewed the Periodic

Surveillance and Preventive Maintenance Activities (AMP B.5.9) and concluded that this

program adequately manages loss of material in- the carbon steel base metal -due to boric acid

corrosion. Sections 3.0.3.2.1 'arid 3.0.3.3.4Aof this SER document the staff's evaluation of these

programs. Based on the preceding discussion, the staff finds that the Water Chemistry Control

Program and the Periodic Surveillance and Preventive Maintenance Activities are acceptable

for managing these aging~effects. ' " '' --

, ,," - ' '

3.3.2.2.5 Loss of Material Due to General, Microbiologically' Influenced, Pitting, and Crevice --

Corrosion

In Section 3.3.2.2.5 of the LRA, the applicant addressed the loss of material from corrosion that

could occur on the 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 c6rrosionhcould occur in the piping and filter housing and supports in the control room

area; the auxiliary and radwaste area' the primary -containment heating and ventilation systems;

the piping of the diesel generator building ventilation system; the aboveground piping and

fittings, valves, and pumps in the diesel fuel oil system; and the diesel engine starting air,

c6ombustion' 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, and closure bolts, equipment frames, and housing of the duct. Loss of material

due to pitting and crevice corrosion'could occur in the heating/cooling coils of the air handler

heating/cooling, anid loss of material due to general corrosion could occur on the external

surfaces of all carbon steel structures and comp6nents, including bolting exposed to operating

temperatures less than 212 -F in the ventilation systems. -The GALL Report recommends

further evaluation to ensure that these aging effects are adequately managed.

In RAI 2.3.3.15-1, the staff questioned why the applicant did not include nonsafety-related air

dryers/aftercoolers in'the air start systems for the EDGs within the scope of license renewal. -In

its response dated April 22, 2004, the applicant stated that the air dryer/aftercoolers assemblies

are in the scope of license renewal and added the air dryers/aftercoolers to the EDG system

AMR summary in-Table 3.3.2-1 5. The staff r6viewed the addition of these components subject

to an AMR 'and'concluded that the addition of these components does not result in the addition

of material-environment combinations or AMPs for the EDG system. -* -

The applicant credited the One-Time Inspection Program (AMP B.5.5) with addressing the loss

'of material due to'corrosion of carbon and low-alloy steel, including galvanized steel, in

ventilation system components (air handling/cooling units), in EDG intake components, and in

EDG startin'g air components where the potenitial exists for significant condensation or pooling

of water 'within the system.' 'In addition, thd applicant will inspect a sample set of carbon steel

components exposed to an air/gas environmrents ipart of the One-Time Inspection Program to

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Ii

confirm that no'significant corrosion is occurring within these components.

The applicant stated that the External Surfaces Monitoring Program (AMP B.5.3) manages

EDG exhaust components and loss of material due to corrosion of the external surfaces of

carbon steel components.

The staff's review of the One-Time Inspection Program and the External Surfaces Monitoring

Program appears in Sections 3.0.3.1 and 3.0.3.3.2 of this SER, respectively. The staff finds

these programs acceptable to manage the aging effect of loss of material in components in the

ventilation systems, emergency generating systems, and external surfaces of carbon steel

components.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the loss of material due to general, pitting, and crevice

corrosion, 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 the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.2.6 Loss of Material Due to General, Galvanic, Pitting, and Crevice Corrosion

In Section 3.3.2.2.6 of the LRA,- the applicant addressed further evaluation of programs to

manage 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 the 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. The Fire Protection Program relies on a combinatidn of visual and volumetric

examinations in accordance with the guidelines of Appendix R to 10 CFR Part 50 and BTP

9.5-1 to manage loss of material from corrosion. However, corrosion may occur at locations

where water from washdowns accumulates. Therefore, the effectiveness of the program

should be verified to ensure that corrosion is not occurring. The GALL Report recommends

further evaluation of programs to manage 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.

The applicant credited the One-Time Inspection Program (AMP B.5.5) with managing the loss

of material due to corrosion on the internal surfaces of components in the RCP oil collection

system and with verifying the effectiveness of the fire protection system.

The' staff's evaluation of the One-Time Inspection Program appears in Section 3.0.3.1 of this

SER. Since the one-time inspection will focus on low points where water could accumulate, the

staff concludes that this program is acceptable to manage the loss of material due to corrosion

on the internal surfaces of components in the RCP oil collection system. In addition, the staff

concludes that the use'of the One-Time Inspection Program to verify the effectiveness of the

fire protection system is consistent with the GALL Report and, therefore, is acceptable.

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On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR -

results involving management of the loss of material due to general, galvanic, pitting, and

crevice corrosion, 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 the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3): - -

3.3.2.2.7 Loss of Material Due to General, Pitting,:Crevice, and Microbiologically Influenced -

Corrosion and Biofouling

In Section 3.3.2.2.7 of the LRA, the applicant addressed further evaluation of programs to

manage loss of material in the diesel fuel oil system to verify the effectiveness of the Fuel Oil

Chemistry Control Program. - .. -

Section 3.3.2.2.7 of the SRP-LR states that loss of material due to general, pitting, and crevice

corrosion, MIC, and biofouling could occur on the internal surfaces of tanks in the diesel fuel oil

system, and loss of material due to general, pitting, land 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 Control Program for monitoring and control of 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 wherebcontaminants accumulate.- The effectiveness of the chemistry control

program should be verified to ensure that corrosion is not occurring.- The GALL Report, -

recommends further evaluation of programs to manage corrosion/biofouling to verify program

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's intended

function will be maintained during the period of extended operation.

The applicant credited the Fuel Oil Chemistry Control Program (AMP B.4.2) and the One-Time

Inspection Program (AMP B.5.5) with managing the aging effect of loss of material for diesel.

fuel oil tanks in the diesel fuel oil system, which is consistent with the GALL Report, with one

exception. The applicant used a different ASTM standard for the Fuel Oil Chemistry Control

Program..

The staff finds the use of a different ASTM standard for the Fuel Oil Chemistry Control Program

acceptable. The staff reviewed the exception to the ASTM standard, which the applicant used

in accordance with TS Section 5.5.13. -The applicant tests for water and sediments, kinematic

viscosity, insolubles, bacteria, and fungi.- The applicant does not test for particulates as

required by the GALL Report. The staff determined that this exception is acceptable, because

sediments are a good indicator of particulates and the standards and criteria used by the.

applicant are consistent with the TS requirements that are part of the CLB. The staff's

evaluations of the Fuel Oil Chemistry Control Program and One-Time Inspection Program are

contained in Sections 3.0.3.2.3 and 3.0.3.1 of this SER, respectively. The staff finds these

programs acceptable to manage the aging effects of loss of materials for diesel fuel oil tanks in

the diesel fuel oil system.

On the basis of its review,' the staff finds that the applicant has appropriately evaluated AMR

results involving the management of the'loss of material due to general, pitting, and crevice

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corrosion, MIC, and biofouling, 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 the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.3.2.2.8 Quality Assurance for Aging Management of Nonsafety-Related Components

See "Quality Assurance Program Attributes Integral to Aging Management Programs" in

Section 3.0.4 of this SER.

3.3.2.2.9 Crack Initiation and Growth Due to Stress-Corrosion Cracking and Cyclic Loading

In Section 3.3.2.2.9 of the LRA, the applicant addressed the further evaluation of programs to

manage cracking in the chemical and volume control system 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 tfie regenerative heat exchanger and in the channel head and

access cover, tubesheet, and tubes of the letdown heat exchanger in the chemical and volume

control system. The Water Chemistry Control Program relies on monitoring and control of

water chemistry based on the guidelines of EPRI TR-105714 for primary water chemistry in

PWRs to manage the effects of crack initiation and growth due to SCC and cyclic loading. The

effectiveness of the chemistry control program should be verified 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 applicant credited the Water Chemistry Control Program (AMP B.3.2) with managing the

aging effect of cracking. Furthermore, a One-Time Inspection performed on ASME Class 1

small-bore piping would serve as an equivalency indicator for any SCC of stainless steel

components in the reactor coolant environment.

The staff finds this is consistent with the GALL Report, Volume 2, Section VII.E1, which

requires a verification program to confirm the adequacy of the Water Chemistry Control

Program to manage cracking. However, this equivalency indicator is not reflected in the

commitment list nor in Appendix A to the LRA for the FSAR Supplement.

In its letter dated July 27, 2004 (SNL Letter No. NL-04-1267), the applicant provided the FNP

License Renewal Future Action Commitment List and included the following statement in

Item 10, under specific components included in the One-Time Inspection sample population:

Examination of Reactor coolant system small bore (<4-inch NPS) ASME Class 1 piping components, consistent with NUREG-1 801 Section XL.M32 requirements, to address NRC concerns regarding cracking

due to SCC or thermal cycling. This examination will also serve as an indicator of the potential for SCC in

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- other stainless steel components exposed to a borated water environment.

Section 3.0.3.2.1 of this SER documents the staff's evaluation of the Water Chemistry Control

Program. The staff finds this program, in conjunction with the commitment, acceptable to

manage the aging effects. -X

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of crack initiation and growth due to SCC and cyclic loading, 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 the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.10 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General

Corrosion -

In Section 3.3.2.2.10 of the LRA, the applicant addressed the reduction of neutron-absorbing

capacity and loss of material due to general corrosion, which could occur in the neutronabsorbing sheets of the spent fuel storage rack in the spent fuel storage system.

Section 3.3.2.2.10 of the SRP-LR states that the 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 system. The GALL Report recommends

further evaluation to ensure that these aging effects are adequately managed.

The applicant stated that this line item applies to boral or boron steel panels in the spent fuel

pool. The applicant uses Boraflex panels, so this line item does not apply to FNP. 'The staff

concurs with this assessment.

3.3.2.2.11 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

In Section 3.3.2.2.11 of the LRA, the applicant addressed the potential for the loss of material in

buried piping of the service water and diesel fuel oil systems.

Section 3.3.2.2.11 of the SRP-LR states that loss of material due to general, pitting, and crevice

corrosion and MIC could occur in the underground piping and fittings in the open-cycle cooling

water system (OCCW) (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,

and operating experience to manage the effects of loss of material from general, pitting, and

crevice corrosion and MIC. To ensure that loss of material is not occurring, 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.

The applicant stated that the AMR results are consistent with this summary item. The applicant

credited the Buried Piping and Tank Inspection Program (AMP B.5.4) with managing the loss of

material on the external surfaces of buried carbon steel piping. The buried piping susceptible to

this aging effect is made of carbon steel coated with a fiber-reinforced coal tar enamel.

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I a

The staff evaluated the Buried Piping and Tank Inspection Program and concluded that it is

adequate to manage the aging effects. Section 3.0.3.2.10 of this SER documents the staff's

evaluation. The staff also reviewed the effectiveness of the Buried Piping and Tank Inspection

Program, including its inspection frequency and operating experience, to ensure that loss of

material is not occurring and that the component intended function will be maintained during the

period of extended operation.

The staff reviewed the applicant's operating history, which indicates that failures of in-scope

buried carbon steel piping resulting from external corrosion have been small and limited to

service water (OCCW system) piping. The applicant attributed these failures to coating

holidays or damage to the coating. However, FNP detected the leaks before any loss of system

function occurred.

Based on its review of the inspection frequency and operating experience, the staff finds that

the Buried Piping and Tank Inspection Program adequately manages the potential for the loss

of material in buried piping of the service water and diesel fuel oil systems. By letter dated

August 31, 2004, the applicant added portions of the compressed air system to the Buried

Piping and Tank Inspection Program.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving the management of the loss of material due to general, pitting, and crevice corrosion

and MIC, 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 the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Conclusion

On the basis of its audit and review, the staff finds that the applicant's further evaluations

conducted in accordance with the GALL Report are consistent with the acceptance criteria in,

Section 3.3.2.2 of the SRP-LR. Since the applicant's AMR results are otherwise consistent with

the GALL report, the staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

current licensing basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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

3.3.2.3.0 General RAIs on AMR Issues

By letter dated March 8, 2004, the-staff requested the applicant to provide additional

information on the issues described in the following general RAIs. By letter dated April 7, 2004,

the applicant responded to these RAls. The following describes these RAls, the applicant's

responses, and the staff's evaluation of the responses.

Aging Effects of Elastomers (RAI 3.3-6)

In several systems (including the control room area ventilation system, the auxiliary and

radwaste area ventilation system, and the liquid waste and drains system), the applicant

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credited the One-Time Inspection Program with managing the aging effects of loss of materials,

change in material property, and cracking for elastomer components. However, the One-Time

Inspection Program is intended for use as a verification AMP to check the degree of aging of

components when'significant aging is not expected, whil6 periodicinspections are more

appropriate if aging effects can reasonably be expected to occur.' The degradation of

elastomers depends upon the service loads and environmental conditions, including

temperature,- radiation level, and presence of aggressive chemicals. -By letter dated March 8,'

2004, in RAI 3.3-6, the staff asked the applicant to provide additional information on the service

loads and environment of the components to justify the use of the One-Time Inspection

Program for managing the aging effects of elastormers.

By letter dated April 7, 2004, the applicant responded by providing the following information. '

Environmental Considerations for Elastomers -

The applicant stated that EPRI TR-1 002950,-"Aging Effects for Structures and Structural ' '

Components (Structural Tools), Revision .1," indicates that elastomers are potentially subject to

thermal degradation.- Thermal degradation results in changes in the elastomer properties and:

potential cracking. The EPRI technical report provides temperature ratings for the evaluated

elastomers ranging from 130 'F for natural rubber to 275 IF for silicone rubber. The EPRI

technical report states that, in general, if the ambient temperature is less than 95 'F, then'

thermal aging is not significant for the period of extended operation. This is a conservative

threshold temperature intended to encompass all elastomer materials. When the specific

elastomer material type is consideredi installation in thermal environments marginally above'.

95 OF may also not be susceptible to significant thermal degradation. ; . .4:f -: -. : . .; _ - _-- :

The applicant also stated that the EPRI technical report indicates'that degradation of natural

rubbers can occur through simultaneous exposure to ultraviolet radiation and oxygen, which

supports an ozone-rubber reaction that embrittles the rubber and can result in cracking or

checking. Sources of ultraviolet radiation include both sunlight and ultraviolet or fluorescent

lamps. Areas exposed to direct sunlight are expected to have the highest potential for

degradation resulting from ultraviolet radiation/ozone exposure since this environment best'

supports both the formation of ozone and the reaction between ozone and natural rubbers. The'

EPRI technical report indicates that nitrile rubber, butyl rubber, silicone rubber, and neoprene'

either have good resistance to or are essentially unaffected by ultraviolet radiation/ozone

degradation. - r - .

The applicant noted that the EPRI technical report indicates that ionizing radiation can

significantly alter the molecular structure and material properties of elastomers; Radiation

levels exceeding 106 rads are the lowest reported threshold for irradiation effects in an

elastomer of the types in scope for license renewal. Conservatively, radiation embrittlement is

postulated for elastomers in locations above this threshold.

The applicant stated that attack by chemical species is also a potential degradation-mechanism.

Experience has shown that exposure to certain chemicals present in nuclear power plants can

embrittle rubbers. According to Table 28-27 of Perry's Chemical Engineees-Handbook, most of

the all-natural and synthetic rubbers offer poor resistance to oils and fuel products. Resistance

to water and acids is fair to good for some rubbers and excellent for others, with resistance tod'

acid attack generally the limiting factor.

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It

FNP Environments for Elastomers in the Scope of the One-Time Inspection Program

Control Room Area Ventilation System. The applicant stated that elastomer components in the

control room area ventilation'system are located inside the non-rad portion of the auxiliary

building. These comiponents are protected from environmental effects, have no radiation

loading, are not subject to attack by aggressive chemicals, and operate at temperatures below

the thrdshold temperature at or above which thermal degradation is a significant concern.

Auxiliary and Radwaste Area' Ventilation System. The applicant stated that the in-scope

elastomer components in the auxiliary and radwaste area ventilation system are divided

between two locations (the rad portion and the non-rad portion of the auxiliary building).

Flexible connectors for the battery room exhaust fans'are located inside the non-rad portion of

the auxiliary building. These components are protected from environmental effects, have no

radiation loading, are not subject to attack by aggressive chemicals, and operate at

temperatures below the threshold temperature at or above which thermal degradation is a

significant concern. Flexible connectors for the penetration room filtration fans are located

inside the rad portion of the auxiliary building. These components are protected from -!

environmental effects, are not subject to attack by aggressive chemicals; and operate at

temperatures below the thresh6ld temperature'at or above' which thermal degradation is a

significant concern. While these components are located in the rad portion of the auxiliary

building, normal operating conditions provide for no significant radiation loading.

Primary Containment Ventilation System. The applicant stated that the in-scope elastomer:

components in the primary containment ventilation system are divided between two locations.

Flexible connectors for the containment purge fans are located inside the rad portion of the

auxiliary building. These components are protected from environmental effects, are not subject

to attack by aggressive'chemicals, and operate at tempeiraftures below the threshold

temperature at or above which thermal degradation is a significant concern. While thesecomponents are located in the rad portion of the auxiliary building, normal operating conditions

provide for no significant radiation loading. Flexible connectors for the containment coolers are

located inside the containment building. These components are replaced periodically as a

preventive maintenance task. These components are therefore short-lived and not subject to

an AMR.

Liquid Waste and Drains System. The applicant stated that the elastomer components in the

liquid waste and drains system are expandable plugs used to plug the penetration room floor

drains. Plugging of the floor drains provides a pressure boundary for the penetration room

filtration system. These floor drain plugs are located inside the rad portion of the auxiliarybuilding. These components are protected from' environmental'effects and the threshold

temperature at or above which thermal degradation is a significant concern. 'While these

components are located in the rad portion of the auxiliary building, normal operating conditions

provide for no significant radiation loading. The floor drain plugs are installed in drains which

would collect leakage and spills. Although unlikely, exposure to aggressive chemicals is

considered. The One-Time Inspection Program will confirm that the plugs have not been

exposed to conditions detrimental to the seals.

The applicant concluded that the One-Time Inspection Program is an appropriate AMP for

these elastomer components. These' elastomer components are installed in locations with

minimal exposure to potential aging mechanisms, and therefore significant aging is not

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I

expected. '

Staff Evaluation of the Applicant's Resp6hse- - ,-.--. - . , m > A ' . -.

The staff reviewed the applicant's responpse t6 RAI 3.3-6. The- staff found the applicant's'

response to issues concerning elastomer components in the'control room area ventilation'

system to be reaso6able and acceptable b-cause the'applicant'has indicated that these

components are protected from envir6rnm6ntaI'effecti, have no- radiation loading,-are not

subject to attack by aggressive ch'emicals, rid bjperate at temperatures below the threshold

temperature at or above which thermal degradation is a significant concern.

The staff also found the applicant's response to issues concerniing flexible connectors for the

containment coolers located inside the conitainment building to be reasonable and acceptable

because the applicant has indicated that'it replaces these components periodically as apreventive maintenance task and, therefore, these components are short-lived and not subject

toan'AMR. -

However; the staff has reviewed the other pa6rts of the applicant's response to'RAI 3.3-6 and'

found that it needed further clarification. ;'

The applicant stated that for the rad portion 'of the auxiliary building, normal 'operating

conditions provide for no significant radiation loading; In a telephone conference on April 26,

2004, the staff asked the applicant to clarify whether under normal operating conditions, the rad

portion of the auxiliary building' is under' a radiati6n loading below that of 106 rads, the lowest

reported threshold for irradiation effects in an'-elastomer of the types within the scope of license

renewal, according to EPRI TR-1 002950. 'The staff also asked the applicant to provide industry

and/or plant-specific operatinig experience' with radiation-related aging degradation of these

elastomer components. ' ' . ' '". - - --

The applicant stated that in the liquid waste and drains system, the floor drain plugs are

installed in drains which would collect leakage and spills, etc, and that although unlikely,

exposure to aggressive chemicals is considered In the same telephone conference, the staff

asked the applicant to clarify the extent of aggressive chemicals in leakage or spills to justify its

conclusion that exposure to aggressive chemicals is unlikely. The staff also asked the applicant

to provide industry ahd/or blant-spebifid operating experience with the aggressive chemicals

related to aging degradatiohi of thesebelastonider-components. .- - -

On April 26, 2004, in a' telephone 'confgrence and later confirmed by letter dated May 28, 2004,

the applicant responded to the staff'scomments described above on the initial response to RAI

3.3-6. The applicant stated that the revised respo'nse to RAI 3.3-6 dated May 28, 2004,

supersedes SNC's response in SNC Letter No';&NL-04-0473, dated April 7, 2004.

The applicant stated that a u'ativ'dose bf.1 x1 06 iads-6ier 60 years would require a -

continuous hourly dose rate of 1.9 rads/hr, or 1900 mrad/hr. The in-scope elastomer

components in the-auxiliary'and radwaste area ventilation system that are located in the rad

portion of the auxiliary building are in rooms 'designated as Radiation Zone lll. The applicant

stated that the projected dose rate in a Radiation Zone ll area is-less than or equal to

15 mre/hr.- .5 rn A,. , - ,-, 

';3:1 81
For in-scope elastomer components in the primary containment ventilation system that are

located in rooms designated as Radiation Zones IlIl and V, the applicant clarified that the

projected dose rate in a Radiation Zone V area exceeds 100 mremlhr. However, the applicant

also stated that recent survey data in the Radiation Zone V rooms showed maximum general

area dose rates in the area of the in-scope components of: 15 mremlhr (Unit 1) and 14 mrem/hr

(Unit 2), with both units operating at 100 percent power. In addition, the applicant stated that

flexible connectors for the containment coolers are located inside the containment building and

that these components are replaced periodically as a preventive maintenance task. The

applicant concluded that these components are therefore short-lived and not subject to an

AMR.

The applicant further stated that the elastomer components in the liquid waste and drains

system are located in rooms designated as Radiation Zone V or less. The applicant stated that

actual dose rates are typically significantly less than 100 nmremhr, as shown in the previous

example for the primary containment ventilation system. in addition, the applicant stated that

the concrete of the floor shields the drain plugs from many sources. The floor drain plugs'are

installed in drains which would collect leakage and spills. The applicant considers exposure to

aggressive chemicals unlikely because the systems in these areas do not contain such

chemicals. Piping containing a mild boric acid solution is the only significant source of chemical

contamination, and leakage from these systems is aggressively controlled. The applicant

stated that although it is unlikely, it considered exposure to aggressive chemicals as having the

potential to accelerate aging of these plugs.

Finally, the applicant concluded that, while significant aging of elastomer components is not

expected because of their installation in locations that have minimal exposure to potential aging

mechanisms, SNC will include the flexible connectors and floor drain plug elastomer

components in the scope of the External Surfaces Monitoring Program (in lieu of the One-Time

Inspection Program). The applicant clarified that the External Surfaces Monitoring Program will

provide for periodic inspection of the elastomer components and will ensure their continued

ability to perform their intended functions.

The staff reviewed the applicant's responses and found them to be reasonable and acceptable

because the applicant indicated that the applicable in-scope elastomer components in the

auxiliary and radwaste area ventilation system, the primary containment ventilation system, and

the liquid waste and drains system are either in Radiation-Zone' lil or Zone V. These

components in these radiation zones will be exposed, over 60 years, to a projected radiation

loading below that of the lowest reported threshold (106 rads) for irradiation effects in an

elastomer of the types in scope for license renewal. In addition, the applicant will include the.-.

flexible connectors and floor drain plug elastomer components in the scope of the External

Surfaces Monitoring Program (in lieu of the One-Time Inspection Program) which includes

periodic inspections of the elastomer components.

Aging Effects of Galvanized Steel Components Exposed to an Inside Environment (RAI 3.3-7)

Galvanized steel components exposed to a moist air environment may experience corrosion.

However, for numerous systems, the LRA states that there is no aging effect on galvanized

steel ducts and fittings exposed to an inside environment, which is moist and humid air. '-

Industry experience may not support this conclusion. By letter dated March 8, 2004, in RAI 3.3-

7, the staff asked the applicant to provide the technical basis for this conclusion in light of

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industry experience. :, -

By letter dated April 7, 2004, the applicant responded that operating experience indicates that

significant condensation is necessary to have an AERM on galvanized steel. For corrosion of

galvanized steel components to occur,-both oxygen and moisture must collect on the .- ;

component surface. Galvanized carbon steel ducts and fittings in the inside environment listed

in the LRA with no AERM do not experience significant condensation/moisture collection,:

-,because they operate at temperatures similar to the surrounding ambient air conditions and

significant condensation is not expected. . . : - -

-The applicant further stated that significant moisture collection/condensation can occur on

galvanized steel ducts and fittings where humid air is exposed to a much colder surface, such

as at cooling coils. Therefore, SNC listed cooling coil units (including their housings) in the LRA

with aging effects associated with moisture collection/condensation. In locations where - -

significant moisture collection/condensation can occur, the AERMs for galvanized carbon steel

were the same as those for plain carbon steel, and therefore SNC elected to include them inthe LRA under a single material type of carbon steel. The applicant provided the following

examples in the LRA:

* * cooling coil units and associated refrigerant piping (housings, coils, fins, drains,

refrigerant lines) in LRA Table 3.3.2-9

* cooling units (housings and fan/coil fins only) in Table 3.3.2-10 -

* equipment frames and housings (includes cooling coil housings and cooling fins) inTable 3.3.2-11

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3-7 and found the response to be

reasonable and acceptable because the applicant indicated that galvanized carbon steel ducts

and fittings in the inside environment listed in the LRA with no AERM do not experience

significant condensation/moisture collection. They do not experience this condition because

they operate at temperatures similar to the surrounding ambient air conditions, and significant

condensation is not expected. Furthermore, the applicant clarified that in locations where

significant moisture collection/condensation can occur, the AERMs for galvanized carbon steel

were the same as for plain carbon steel.- Therefore, the applicant elected to include them in the

LRA under a single material type of carbon steel.- ' -

Aging Effects of Galvanized Steel Components Exposed to Borated Water (RAI 3.3-8)

In several systems (for example, the auxiliary and radwaste area ventilation system and the fire

protection system), the applicant identified the loss of materials as a plausible aging effect for

galvanized steel components in the inside environment and credited the Borated Water

'Leakage Assessment and Evaluation Program with managing this aging effect. However,

galvanized steel components are not in the scope of the Borated Water Leakage Assessment

and Evaluation Program, and it is not clear~from the LRA what mitigation or corrective actions

the applicant will take if it detects such corrosion. -By letter dated March 8, 2004, in RAI 3.3-8,

the staff asked the applicant to provide information on the effects of boric acid corrosion on the

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9

galvanized steel components and how it will manage this aging effect. The staff also asked the

applicant to provide operating experience, if any, relating to boric acid corrosion of the relevant

galvanized steel components.

By letter dated April 7, 2004, the applicant responded that the reference to carbon steel

components in LRA Section B.3.5 includes all components that are fabricated from a carbon

steel base metal. For the FNP LRA, the designation of carbon steel includes galvanized steel

components such as the galvanized steel ducts and fire protection components identified in the

LRA and alloy steels such as those used in bolting.

The applicant also stated that the Borated Water Leakage Assessment and Evaluation Program

inspects borated water systems at FNP for leakage and evidence of leakage. When boric acid

leaks are discovered, the program identifies the components within the boric acid leak-path in

addition to the leakage source, so that the operators can take appropriate corrective action.

The applicant claimed that a review of plant-specific operating experience revealed no evidence

of loss of material due to boric acid corrosion of galvanized steel components, including those

within the scope of license renewal.

The applicant stated that the galvanized material of these components consists of carbon steel

coated with a thin outer layer of zinc. The zinc tends to neutralize any acidic moisture that

makes contact with the material surface.

The applicant further stated that because of the protective nature of the zinc coating of the

carbon steel surface, loss of material due to boric acid is expected to be less severe than in the

case of plain carbon steel but is still assumed to occur. The applicant has conservatively

included galvanized carbon steel materials located near borated water system components

within the scope of the Borated Water Leakage Assessment and Evaluation Program.

Therefore, the applicant concluded that loss of material in the inside environment for galvanized

carbon steel components will be adequately managed during the period of extended operation.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3-8 and found it to be reasonable and

acceptable because the applicant indicated that the applicant inspects the borated water

systems at FNP for leakage and evidence of leakage in accordance with the Borated Water

Leakage Assessment and Evaluation Program, and that the applicant conservatively included

galvanized carbon steel materials located near borated water system components within the

program scope.

Clarification of the Definition of "Inside Environment" for All Buildings (RAI 3.3-9)

In Table 3.0.4-1 of the LRA, the applicant provided specifics of the inside environment. fIn

particular, it provided the average temperature of 120 'F and the humidity range of 5-95

percent within the containment. By letter dated March 8, 2004, in RAI 3.3-9, the staff asked the

applicant to clarify whether it'expects the conditions specified for the containment environment

to be bounding for the inside environment for all those buildings listed in the description column,

and whether it assumes that those conditions apply to the aging of all components in an inside

environment. The staff also asked the applicant to discuss whether conditions exist that render

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components susceptible to periodic wetting and'drying and,'if so, to address the issue of

applicable aging effects in' thde types of inside.environments. -

By letter dated April 7, 2004, the applicant'responded that it had used the inside environmental

descriptor in the LRA to represent the containment environment and the environments found

within enviroinfentally controlled structures2 The minimunmtemperature in these structures is

controlled toprevent freezing. Veritilation-is also provided. Although environmental conditions

inside containnent are theabounding cbnditions for the inside environment, the applicant

conside6red t6'i&ctual c6riditions experienced, including operating experience, in the AMRs.-

The applicant also stated that in evaluating the'ootential for condensation and water pooling, it

assumed all a're'as with an inside envir6nment to have high relative humridity. The operating

temperature range f'r'the process fluid drives the potential for condensation and periodic

wetting and drying, such as that which occurs in relatively cold service water and in the various

cooling coil units. Antisweat insulation is installed on the piping which is most prone to

condensing atmosoheric moisture. Process lines that operate at high temperatures result in

localized temperatures above the ambient conditions and therefore do not have a potential for

periodic wietting and drying. ''In the AMRs, the-applicant evaluated the potential for periodic

wetting and drying for the individual c6mponents aid for AMP selection. For susceptible--

materials in susceptible locations, the'appli6ant identified loss of material as an AERM in theinside environment.

The applicant indicated that in evaluating elastomers (discussed in the response to RAI 3.3-6),

it considered the localized temperatures-and radiation levels in the AMRs.

Staff Evaluation of the Applicant's Response ;'

The'staff reviewed the applicant's response to RAI 3.3-9 and found the response to be

reasonable and acceptable because the applicant showed that environmental conditions inside

containment are the bounding conditions for the inside environment, and because the applicant

considered the actual conditions'experienced,'including the potential for periodic wetting and

drying as well a' operating experience,'in the-AMRs. -'

Use of Water Chemistry Control Program With6ut an'Inspection for Managing the Loss of

Material for Stainless Steel Components (RAI 3.3-1 0)

The Water Chemistry Control Program is normally augmented by an inspection program to

verify the effectiveness of the AMP, especially for stagnant or low-flow areas. For example, the

applicant credited the Water Chemistry Control Program augmented by the One-Time.-:i

Inspection Program'With managing the aging effects for carbon steel components exposed to

the CCCW environment. However, for several aiuxiliary systems, the applicant credited the.-:,

Water Chemistry C6ntrol Program with managing'the'loss of material forthe stainless steel

components exposed to borated water or treated water (including closed-cooling water) without

augmentation by an inspection program. By letter dated March 8, 2004, in RAI 3.3-10, the staff

asked the applicant to justify the use'of the Water'Chemistry Control'Program without an

inspection program to verify its'effectiveniiss for managing the loss of material for stainless

steel components.' * ' ' , -

By letter dated April 7, 2004, the applicant responded by pointing out that NUREG-1 801,

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I ft

Section XLI.M2, recommends a one-time inspection of selected components at susceptible

locations in the system. The applicant stated that it cannot identify any NUREG-1 801

recommendation for a one-time inspection of stainless steel auxiliary system group components

exposed to borated water or treated water environments.

The applicant also stated that NUREG-1 801 recognizes that the preventive nature of the Water

Chemistry Control Program is generally considered to be adequate to manage the effects of

aging through the period of extended operation for stainless steel components exposed to

borated water or treated water, including CCCW. Inspection programs are not considered

necessary for all systems and components because of the noncorrosive environments and the

corrosion-resistant nature of stainless steels. Therefore, NUREG-1801 does not normally

require for stainless steel component types that water chemistry control be augmented by an

inspection program. The applicant claimed that its AMR results are consistent with the AMPs

recommended by NUREG-1801.

The applicant stated that stainless steel components derive their corrosion resistance from the

thin, tightly adherent, passive chromium oxide layer that forms at the component surface. If the

environmental conditions are not sufficiently aggressive to penetrate this oxide layer, then no

significant corrosion is expected to result. Conversely, if the environment is sufficiently

aggressive to disrupt the oxide layer, then localized corrosion may occur.

The applicant further stated that for austenitic stainless steels, penetration of the passive

chromium oxide layer and subsequent corrosion has been shown to be principally related to the

oxidizing nature of the environment and the presence of specific detrimental ionic species

known to interfere with the passivation process (most notably chlorides, sulfates, and fluorides).

Appendix A to EPRI TR-1 003056 indicates that localized corrosion of stainless steels exposed

to treated water (including borated water) is not a significant concern when dissolved oxygen

concentrations are less than 100 ppb and concentrations of detrimental ionic species are less

than 150 ppb.

Borated Water Environment; NUREG-1 801 acknowledges that loss of material due to pitting

and crevice corrosion is not an aging effect/mechanism requiring management for stainless

steel components exposed to a borated water environment. Specifically, several sections of

NUREG-1 801 (e.g., Sections V.D1, VII.A3, and VII.E1) conclude that stainless steel

components are not subject to significant general, pitting, and crevice corrosionr in a borated

water environment; therefore, NUREG-1 801 does not include these aging mechanisms for this

material-environment combination.

The applicant agreed that in the normal borated water environment, stainless steel components

are not subject to significant general, pitting, and crevice corrosion. The applicant claimed that

it had conservatively identified loss of material due to pitting and crevice corrosion as a potential

aging effect that is adequately managed by the Water Chemistry Control Program without

supplemental one-time inspections.

The applicant stated that it implements the FNP Water Chemistry Control Program consistent

with the PWR primary water chemistry guidelines in EPRI TR-105714. This chemistry control

program provides for both a strongly reducing environment via the addition of oxygen

scavengers and strict control of detrimental ionic species. These controls limit both dissolved

oxygen and detrimental ionic species concentrations to values well below those specified by

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EPRI TR-1003056.

The applicant also stated that FNP and industrywide operating experience confirm that pitting

and crevice' corrosion of austenitic stainless steels has not been an issue.of concern. Inservice

inspections performed at FNP in accordance with Section Xl of the ASME Code include

numerous inspection locations consisting of the borated water/stainless steel material-' -

environment combination and include nbrmarilly stfgrn t and low-flow areas. Inservice

inspections include both pipe welds and component internal surfaces. The examinations would

identify crevice corrosion or pitting. The applicant has performed these ISIs for many years, -

and they do not indicate a history of, or susceptibility to, loss of material due to pitting or crevice

corrosion.

Treated Water Environment (Reactor Makeup Water System, Demineralized Water System.,

-Sampling Svstem). The applicant clarified that this discussion of treated water includes steam,

and power conversion systems because portions of the 'SG blowdown system sample lines are

in the scope of the 'sampling system. The auxiliary systems group includes the sampling

system. - - -

The applicant stated that it implements the FNP Water Chemistry Control Program consistent

with the guidelines in EPRI EPRI TR-1 05714 and EPRI TR-102134. The Water Chemistry

Control Program provides for strict control of detrimental ionic species concentrations to values

well below those specified by EPRI TR-1 003056.-;Sulfates and chlorides are monitored in SG

blowdown since SG blowdown provides a reliable indicator of anion content throughout the

turbine cycle.-- Additionally, chloride, fluoride, and sulfate content and total conductivity are

monitored at appropriate points during the production of makeup water in the water treatment

plant. These controls limit detrimental ionic species concentrations to values well below those

specified by EPRI TR-1003056 as contributing to corrosion.-

Dissolved oxygen is monitored in the condensate and feedwater systems, CST, reactor makeup

water storage tank,'and in the water treatment plant during production of demineralized water.

Oxygen 'scavengers such as' hydrazine typically control dissolved oxygen in steam and power

conversion systems. In the CST and reactor makeup water storage tank, tank bladders control

dissolved oxygen. Dissolved oxygen is expected to'be rapidly depleted in stagnant treated

water systems; therefore, it is controlled in those systems where a high oxygen concentration

could contribute to accelerated corrosion.

The applicant further stated that FNP and industrywide operating experience confirm that pitting

and crevice corrosion of austenitic stainless steels has not been an issue of concern. Reviews

of FNP operating experience do not indicate a susceptibility to loss of material for stainless

steel components in a treat6d water environment:,

Closed-Cycle Cooling Water Environment. -The applicant stated that the FNP Water Chemistry

Control Program limits chlorides and fluorides in the CCW system to the low range of parts per

million. -These limits are consistent with the limits provided in EPRI TR-1 07396, "Closed-Cycle

Cooling Water Chemistry Guideline." Chlorides and fluorides are monitored in the EDG jacket

water system as an indicator of inleakage.-:Also,'pH in CCCW systems is maintained greater

than neutral to'reduce the potential for crevice corrosion and pitting by promoting stabilization of

the passive oxide layer.

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Il

The applicant further stated that dissolved oxygen and sulfates are not monitored or controlled

in the CCCW systems. However, these parameters are monitored at appropriate points during

the production of makeup water in the water treatment plant. Water treatment plant effluent is

also monitored for total conductivity to ensure that unacceptable levels of ionic species are not

introduced via makeup-water. Finally, any dissolved oxygen introduced via makeup water is

expected to be rapidly depleted. Without a significant ingress source, dissolved oxygen

concentrations do not require control (EPRI TR-107396).

Control of ionic species which disrupt the passive oxide layer found on stainless steels,

monitoring of dissolved oxygen in the makeup water, and pH adjustment effectively eliminate

corrosion as an aging effect for stainless steels in these systems.

The applicant stated that FNP and industrywide operating experience confirm that pitting and

crevice corrosion of austenitic stainless steels has not been an issue of concern. FNP monitors

for corrosion in CCCW systems. Visual inspections of selected components are performed

when they are opened for maintenance. These inspections have consistently found no visible

corrosion. The applicant indicated that reviews of FNP operating experience do not indicate a

susceptibility to loss of material for stainless steel components in a closed-cooling water

environment.

The applicant concluded that industry and plant-specific operating history has demonstrated

that the Water Chemistry Control Program has effectively controlled loss of material due to

corrosion of stainless steel components exposed to borated water, treated water, and closedcooling water. Therefore additional one-time inspections of stainless steel auxiliary system

components for loss of material due to corrosion are not considered necessary.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3-10 and found the response to be

reasonable and acceptable because the applicant has shown that its Water Chemistry.Control

Program is consistent with the industry guidelines (EPRI TR-1 05714, EPRI TR-1 02134, EPRI

TR-1 07396, and Appendix A to EPRI TR-1 003056). In addition, the applicant has indicated that

its plant-specific operating experience confirms that pitting and crevice corrosion of austenitic

stainless steels has not been an issue of concern in treated water, borated water, and CCCW

environments.

Use of One-Time Inspection Program to Manage the Aging Effects of Stainless Steel and

Carbon Steel in Raw Water and Lube Oil Environments (RAI 3;3-1 1)

The loss of material due to general, pitting, and crevice corrosion, MIC and biofouling is a

plausible aging effect for stainless steel and carbon steel in the raw water environment or

stainless steel expos6d to lube oil that may be contaminated with water; In the LRA, the

applicant credited the One-Time Inspection Program with managing the loss of material aging

effect on stainless steel and carbon steel piping and valve bodies exposed to a raw water

environment or stainless steel components exposed to lube oil that may be contaminated with

water. However, the staff notes that the One-Time Inspection Program is intended for use as a

verification AMP to check the degree of aging of components when significant aging is not -

expected, while periodic inspections are more appropriate if aging effects can reasonably be

expected to occur. By letter dated March 8, 2004, in RAI 3.3-11, the staff asked the applicant

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to justify why the One-Time Ins'pe6tion Program isI appropriate for mlanaging the identified aging

effect.

By letter dated April 7, 2004, the applicant responded by providing the following information.

The staff reviewed and evaluated the following:

Stainless Steel Exposed to Lubricating Oil w/ Potential Water Contamination (RCP Oil

Collection System):

In Section 3.3 (Aging Management of Auxiliary Systems) of the LRA, SNC credits the One-Time

Inspection (OTI) Program to manage stainless steel components in a lubricating oil

environment for the RCP oil collection system.' The RCP oil collection system is an "open' oil

leakage collection system which is designed to collect potential external leakage from the RCP

motor lubricating oil system. The RCP oil collection system includes "open" drip pans and

therefore the presence of water contamination from the general area environment was

assumed to be plausible although significant contamination is not anticipated. Stainless steel is

very resistagnt to general corrosion, pitting, crevice, and MIC, and biofouling is not expected.

Additionally, the applicant indicated the FNP operating experience review did not identify any

applicable aging issues. Therefore,'SNC considers use of the OTI Program for the stainless

steel components in the RCP oil'collection system appropriate to confirm no significant aging is

occurring.

Stainless Steel and Carbon Steel Pipinq and Valve Bodies Exposed to Raw (Unmonitored)

Water Environment

The applicant-stated that it credited the One-Time Inspection Program for the following carbon

steel and stainless steel components that areexposed to raw water:

* - control room air conditioning cooling coil units

* drain piping and valves in the liquid waste and drains system

* piping, valves, and a tank in the potable -and sanitary water system

The applicant clarified that these systems operate -at low pressure and ambient temperature. - While some degree of corrosion is expected in these components, SNC does not expect these

components to undergo significant aging that could cause the loss of component intended

functions. If SNC discovers significant aging, it will initiate appropriate corrective action to

ensure that the intended functions are maintained during the period of extended operation.

Control Room Air Conditioning Cooling Coil Units:

The raw water environimrent for these units is'moisture/condensation that may form on the units.

The units'are designed for this environment with the selection of materials intended to provide

reliable service. The carbon steel that may potentially be wetted is galvanized.- The One-Time

Inspection Program is appropriate to inspect the unit and confirm significant aging is not

occurring. " - .

Drain Piping And Valves In The Liquid Waste And Drains System:

The drain piping and valves in the liquid waste and drains system operate at low pressure and

; 3-189
I -

temperature and are used on an intermittent basis. Typically the piping is "dry", however the

LRA environment assumes the most limiting environment of "raw water." This raw water is

better characterized as an "unmonitored and uncontrolled water" source. The One-Time

Inspection Program is appropriate to inspect and confirm significant aging is not occurring in the

drain piping and valves.

Piping. Valves, and Tank In The Potable And Sanitary Water System:

Although described as 'raw water," the potable and sanitary water system water is "Well water

or potable water" as described in LRA Table 3.0.4-1. The water is taken from deep wells and

run through clarifiers. Operating experience with these types of systems does not indicate SNC

should expect significant aging. The One-Time Inspection Program is appropriate to inspect

and confirm significant aging is not occurring.

The applicant also stated that these systems operate at low pressure and ambient temperature.

While some degree of corrosion is expected in these components, SNC does not expect

significant aging to occur. The applicant will use the One-Time Inspection Program to

determine if corrosion has occurred during the current operating term to such an extent that

additional actions might be required during the renewal term. The applicant stated that such

actions could include additional inspections, component replacements, or other appropriate

measures.

Staff Evaluation of the Applicant's Response

The staff reviewed the, applicant's response to RAI 3.3-11 and found the response to issues

concerning stainless steel exposed to lubricating oil with potential water contamination (RCP oil

collection system) to be reasonable and acceptable because stainless steel is very resistant to

general, pitting, and crevice corrosion, and MIC, and because biofouling is not expected. In

addition, the FNP operating experience review did not identify any applicable aging issues.

The staff also found the applicant's response to the issues concerning piping, valves, and tanks

in the potable and sanitary water system to be reasonable and acceptable, because the

applicant indicated that the water is taken from deep wells and run through clarifiers, and the

applicant indicated that, based on operating experience with these types of systems, it does not

expect significant aging to occur.

However, in its review of the other parts of the applicant's response to RAI 3.3-11, the staff

found that it needed further clarification.

The applicant stated that, for the control room air conditioning cooling coil units, the raw water

environment for these units is moisture/condensation that may form on the units. In a

telephone conference on April 26, 2004, the staff asked the applicant to clarify whether

moisture/condensation coupled with subsequent drying via evaporation/runoff will lead to an

ongoing intermittent/periodic wetting/drying environment. If so, the staff asked the applicant to

clarify whether the One-Time Inspection Program is appropriate to inspect the unit and confirm

that significant aging is not occurring in the control room air conditioning cooling coil units.

The applicant also stated that the components of drain piping and valves in the liquid waste and

drains system operate at low pressure and temperature and are used intermittently, and that,

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the raw water is characterized as an unmonitored and uncontrolled water source. In a

telephone conference on April 26, 2004, the staff asked the applicant to clarify whether this

unmonitored and uncontrolled water source,' introduced to these components on an intermittent

basis, will lead to an intermittent/periodic wetting/drying environment. If so, the staff asked the

applicant to clarify whether the One-Time Inspection Program is appropriate to inspect and

confirm that significant aging is not occurring in the drain piping and valves.

In the April 26, 2004, telephone conference and as confirmed in a letter dated May 28, 2004,

the applicant responded to the staff's comments described above on the initial response to RAI

3.3-11 with the following supplemental information.

For the control room air conditioning (A/C) cooling coil units (including the drain and loop seal -

piping), the applicant stated that the control room A/C cooling coil units operate year round with

moisture/condensation on the cooling coils expected throughout most of the year because of

the normally warm and humid outdoor environment.; Drying of the cooling coils occurs when the

supply air's dew point is below the coil temperature (typically during colder weather) and also

occurs when swapping over to a different cooling unit. As a result, normal operation results in

infrequent wet/dry cycling of the cooling coils and associated drain and loop seal piping. The

loop seal feature further limits the wet/dry cycling frequency for the in-scope piping.

The applicant indicated that the exposed surfaces of the cooling coil frames are galvanized

carbon steel, while the drain and loop seal piping is plain carbon steel. Since wet/dry cycling is

infrequent, the loss of material degradation is expected to progress slowly. Cooling coils of

similar design (copper alloy tubes with aluminum fins and galvanized steel framing) have

proven reliable in A/C applications. The drain and loop seal piping is a 1-1/2-inch, Schedule 40

design. Since the gravity drainlines operate at atmospheric pressure, significant corrosion

allowance is available. The applicant stated that a review of the FNP operating experience did

not identify any history of corrosion-related failure (i.e., loss of material) for the control room A/C

cooling coils or other similar units, or the drain and loop seal piping.

The applicant further stated that it replaced the control room A/C cooling coil units at FNP (circa

1997) as part of an overall upgrade/modification of the control room A/C system. The -

upgrade/modification replaced the original water-cooled control room ANC units with air-cooled

A/C units and included independent refrigeration systems such as cooling coils.

Based on the FNP and industry operating experience to date, the recent replacement of the

cooling coils, and the low frequency of wet/dry cycling, the applicant concluded that the .

selection of the One-Time Inspection Program as the AMP for the control room A/C cooling

coils is justified. The applicant stated that it will perform the one-time inspection to confirm that

.loss of material degradation of the control room ANC cooling coil units is progressing slowly and

will not threaten their integrity during the period of extended operation. The applicant will use

the One-Time Inspection Program to predict the potential for through-wall leakage occurring in

the drain and loop seal piping during the period of extended operation. The inspections will

determine the need for corrective actions such as future inspections or repair/replacement.

Finally, the applicant clarified that fouling does not apply to the license renewal component

intended function of pressure boundary and therefore should not have been listed.

With respect to the drain piping and valves in the liquid waste and drains system, the applicant

3-1 91
I

emphasized that the liquid waste'and drains system operates at low pressures and- -

temperatures (classified as a low-energy system in the CLB)'. The gravity drainlines operate at

atmospheric pressure, and therefore a large corrosion allowance is available. Other in-scope

portions are only above atmospheric pressure during sump or transfer pump operation.

The applicant stated that the drain piping-components in the liquid waste and drains system are

typically dry with a low frequency of wet/dry cycling. These normally dry drains are infrequently

exposed to raw water (characterized as unmonitored and uncontrolled water) from draining

equipment to support maintenance and from other sources such as abnormal leakage (before

corrective maintenance) that is routed to the floor drain. A few drains receive continuous lowvolume drainage, such as condensate from air handling units, and therefore are typically

partially wetted with a low frequency of wet/dry cycling.' Small portions of the system are

normally filled, such as pump discharge piping and the drain traps/loop seals.

The applicant also stated that for the stainless steel piping components exposed to raw water,

the One-Time Inspection Program will confirm that loss of material is not occurring or is

progressing very slowly so as not to affect the component intended function. The use of a.

one-time inspection (instead of a' periodic inspection program) as the AMP is justified based on

the inherent corrosion resistance of stainless'steels and the supporting operating experience.

Stainless steels have provided reliable service in the liquid waste and drains system and similar

applications. The applicant stated that the operating experience review (both plant-specific and

industrywide) performed in support of the LRA did not identify age-related failures of stainless

steels in similar service.

The applicant stated that the FNP carbon steel piping components exposed to raw water are in

scope under the 10 CFR 54.4(a)(2) criterion. For the carbon steel piping components exposed

to raw water, pressure boundary loss of material is managed by a combination of the One-Time

Inspection Program, the External Surfaces Monitoring Program, and the Borated Water

Leakage Assessment and Evaluation Program (where components are potentially exposed to

borated water leakage). The applicant further stated that it will use the One-Time Inspection

Program in areas where a potential spatial interaction exists between a leaking drainline and a

safety-related system, structure, or component, such as where a drainline runs over sensitive

components, to predict the potential for through-wall leakage occurring during the period of

extended operations The inspections will determine the need for corrective actions such as

future inspections or repair/replacement.

The applicant stated that the use of a one-time inspection (and not a periodic inspection

program) as the AMP for the carbon steel piping components is justified because it targets the

locations-where there is'potential interaction with sensitive-components, and because it has,

other programs in place that will detect leakage (and initiate corrective action) before a failure of

the safety-related system, structure, or component occurs. The AMPs that monitor the exterior

of the liquid waste and drain system carbon steel piping components and the AMPs designated

in the LRA to monitor the exterior of the safety-related systems, structures, or components

(e.g., the External Surfaces Monitoring Program, the Borated Water Leakage Assessment and

Evaluation Program, and the Structural Monitoring Program) are reasonably assured to detect

leakage before a failure of the safety-related system, structure, or component occurs. The

applicant indicated that the FNP operating experience confirms that leakage is readily identified

and remedial action taken.

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The staff reviewed the appicant's responses and found the responses to be reasonable and

acceptable because (1) the applicant used the'FNP and industry ojperating experience to date,

the recent replacement of the cooling coils, and the low frequency of wet/dry cycling for the

applicable components in the control roomA/C cooling coil units (including the drain and loop seal piping) as justification for the use of the One-Timle Inspection'Pcigram as an AMP--and (2)

the applicant clarified that, for the applicable drain piping and valves in the liquid waste and

drains system, the piping components are typically dry and are infrequently' exp6sed tod raw

water from the drains system. The inherent corrosion resistance of the stainless steel'

components, the use of other programs to detectlea'kage for the carbon steel piping

components,- and the FNP's experience also support the applicant's choice of a one-time

inspection as the AMP.

Justification of Different AMR Results for the Same Material/Environment Combination (RAI

3.3-12) ' '' ' ' ' ~ ' ---- -~

In Tables 3.3.2-10 and 3.3.2-11, for copper alloy components exposed to'an inside

environment, the LRA identified loss of material'as the AERM for some components (cooling'

units) but'concluded that there are no aging effects for other components (Pitot tubes). -By

letter dated March 8, 2004, in RAI 3.3-12, the staff asked the applicant to justify the different

AMR results for the same material-environment combination.

'By letter'dated April 7, 2004, the applicant responded that the AMR for copper alloycomponents'exposed to an inside environment evaluates the potential for water to pool on' the

surfaces (external) and the likelihood that the components will be wetted. Copper materials that

.could be exposed to repeated wetting or the pooling of water can experience loss of material.

The applicant further stated that the cooling coils and fins for HVAC units are examples of

locations where the external surfaces are likely to be wetted regularly because of c`ondensation'.

The applicant identified loss of material as an AERM for copper alloy components in an inside

environment 'with' a'potential for significant wetting or water pooling.' The Pitot tubes are''an

example of a 6omponent whose external surfaceis not likely to be'wetted or exi6'sed t6 pooled

water in the inside environment. Thus, SNC has noit identified loss of material as an AERM in

an inside'environment for that component.

Staff Evaluation of the Applicant's Response

The staff has reviewed the applicant's response to RAI 3.3-12 and found it to be reasonable

and acceptable because the applicant has clarified the difference in AMR results between the

Pitot tubes and the cooling coils and f ins for HVAC- units in an inside environment.

Measures for Maintaining and Verifyino the iDrvne Level in the Gas Environment (RAI 3.3-13)

The applicant stated that compressed air system (Table 3.3.2-7) and EDG system (Table

3.3.2-15) components in ardried gas erivironrment h'a've no'applicable agin g effects. The

applicant described a dried gas environment as containing noncondensible vapor with a very

limited percentage of'moisture present.-Dried gases include co6rpressed air (downstream of air

dryers) and bottled gases such as'carbon dioxide, hydrogen, nitrogen, oxygen, and refrigerants.

The staff agrees that the gaspis relatively dry and moisture-free. However, moisture present in

gas may be a major contributor to aging degradation. By letter dated March 8, 2004, in RAI

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I M*

3.3-13, the staff asked the applicant to discuss the measures for maintaining and verifying the

dryness level in the gas environment, inicluding the acceptance criteria and their bases.

By letter dated April 7, 2004, th'e applicant responded that dry bottled gases are produced by

compressed gas vendors and meet manufacturer'& standards as.well as industry standards for

moisture content., Typical dew'points rangd from -90 OF to -80 OF or approximately 3.5 ppm

water vapor to 7.8 ppm water vapor. The applicant also noted that purity levels for bottled

gases typically run in the range of 99.50 to 99.999'percent. Impurities represent those

constituents in the cylinder that are not pure gas, and a portion of this impurity includes the

small amount of water vapor. The applicant claimed that it is evident that the water vapor

potential is extremely low for these'dry bottled gases and that any moisture carryover into plant

systems is insignificant.

The applicant also stated that air dryers are located in compressed air systems to provide dry

air for the air distribution network, or in the case of the EDGs, for the air start headers. Air

dryers and receivers are natural collection points for moisture and are automatically drained of.

water and also periodically drained by manual'actions t6assure that no significan't amounts of

water enter the systems. The 'gs is relatively dry and moisture-free downstream of the air

dryer.

The applicant stated that it replaces the desiccant in the EDG air-start air dryers every 3

months, regardless of condition. The compressed air system has. redundant air dryers installed

that operate with continuous regeneration and are designed to reduce the dew point of the air

Jto - 40 OF. The dew point is' measur6d on the air dryers every 6 months, and desiccant is

inspected and replaced yearly if needed in the compressed air system air dryers. The quality of

compressed air is periodically monitored at selected locations. The acceptance criteria for dew

point is that it must be at least 18 OF below the minimum temperature to which the instrument

air system is exposed.

In summary, the, applicant- indicated that the operating history at FNP did not indicate any

significant aging degradationr in systems exposed to a dried gas environment. The design,'

features (dry bottled gases and air dryers), actio-ns taken (monitoring of dew points and,

replacement of desiccant), and operating history showed that the air systems' internal

environment where indicated in the LRA as dried gas is relatively dry and moisture-free and has

no applicable AERM for the period of extended operation.

Staff Evaluation of the Applicant's Response

The staff has reviewed the applicant's response to RAI 3.3-13 and found it to be reasonable

and acceptable because the applicant'clarified that the quality of compressed air is periodically

monitored at selected locations and that the operating history at FNP does not indicate any

significant aging degradation' in systems exposed to a dried gas environment.

Measures for Maintainino and Verifying the Dryness of the Lube Oil Environment (RAI 3.3-14)

For several auxiliary systems such as the oil-static cable pressurization system and EDG

system, the applicant concluded that there are'noa applicable aging effects for components in a

lube oil environment. The staff agrees with this positi6n if the lube oil is relatively dry and '

water-free. However, moisture present in lube oil may be a major contributor to aging

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degradation. During operations, moisture may accumulate, even though fresh oil may be

relatively dry and water-free initially. By letter dated March 8, 2004, in RAI 3.3-14, the staff

asked the applicant to describe the measures for 'rnintaining and verifying the dryness of the'

lube oil, including the acceptance criteria and their bases.

By letter dated April 7, 2004, the applicant responded. The applicant concluded that the

lubricating oil environments for the following auxiliary systems (LRA Section 3.3) are not

potentially water contaminated:

0

0

0

open-cycle cooling water-air compressor lubricating oil

emergency diesel generators-lubeoil systems for the emergency diesel generators

' oil-static cable pressurization-oil-static cable'pressurization system*

The applicant stated that lubricating oil systers are typically closed systems that have little

potential for ingress of contaminates unless a comiponent failure occurs. License renewal does

not assume component failures as a means to-establish the conditions necessary for aging to

occur. Water contamination of lubricating oil in a closed lubricating oil system is event-driven

and addressed by corrective action. Operating experience at FNP confirms that lubricating oil

systems are not susceptible to loss of material caused by water contamination.

The applicant further stated that the activities described below are routine operating and.

maintenance activities which are not credited as AMPs. Operators check the oil levels daily

during their rounds for the affected systems. 'Gross Water contamination of lubricating oil can

be visually identified by increased oil level or'the oil presenting a milky appearance.

One'n-Cvcle Cooling Water-Air Compressor Lubricating Oil. The subject air compressors are

within the scope of license renewal as part of FNP's 10 CFR 50.48 compliance licensing basis

(Appendix R to 10 CFR Part 50, concerning safe shutdown). The lubricating oil in these air

compressors is changed annually during the'domrpressor overhaul.

Emeriency Diesel Generators-Lube Oil Systems for the Emergency Diesel Generators;.The

EDG oil samples are obtained and analyzed with acceptance criteria established in accordance

with manufacturer's or user's group recommendations. Lubricating oil may be either reused or

replaced with new oil 'as required by sample iresults.T Operating conditions in the EDGs preclude

accumulation of significant moisture in the lubricating bil from environmental sources. The high'

operating temperature of the EDGs would vaporize any moisture in the oil, and the crankcase

vacuum pump would evacuate the moisture!. When the EDG is not operating, the keep-warm

system maintains the lube oil at terilperatures'above the ambient conditions. :

Oil-Static Cable Pressuriization Svstem. The oil-stitic cable pressurization system is designed,

to prevent moisture intrusion. The system operates to maintain a continuous pressure ofgreater than 180 psig downstream of the oil pumnps. Upstream of the oil pumps, a nitrogen

overpressure of 8 psig is maintained on the storage tanks to prevent intrusion of moisture and

other contaminants. Operators monitor both pressures during their rounds, and both have lowpressure alarms to ensure prompt corrective action for low-pressure conditions. There is no

credible mechanism for moisture to accumulatein this system. However,- moisture content is

one of the parameters monitored and trended for-this system. Sample results typically run 10

ppm or less.

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I .. .. - Staff Evaluation of the Applicanrs Response,

The staff reviewed the applicant's response to RAI 3.3-14 and found the response to be

reasonable and acceptable because the applicant has shown that water contamination of

lubricating oil in a closed lubricating oil system is event-driven and addressed by corrective

action and because operating experience confirms that lubricating oil systems are not

susceptible to loss of material caused by water contamination.

Inspections or Monitoring of Heat Exchangers (RAI 3.3-15)

Several auxiliary systems, such as the spent fuel pool cooling and cleanup system, CCCW

system, sampling system, and chemical and volume control system, have heat exchangers that

are cooled by the CCCW system. It is not clear in the LRA whether the applicant performs

inspections and monitoring on the subcomponents (e.g., tubesheets and tubes) exposed to

CCCW. By letter dated March 8, 2004, in RAI 3.3-15, the staff asked the applicant to clarify the

types of inspections or monitoring that it will perform on the heat exchangers.

By letter dated April 7, 2004, the applicant responded that the LRA 3.3.2-x series of tables

provides the specific aging management strategy applied to each auxiliary system heat

exchanger component (e.g., tubesheets and tubes, as noted in the tables). The Water

Chemistry Control Program manages all heat exchanger components in contact with CCCW.

The preventive nature of the Water Chemistry Control Program will adequately manage the

effects of corrosion, selective leaching, and cracking throughout the period of extended

operation for heat exchanger components exposed to a CCCW environment. While inspections

are generally considered unnecessary, the applicant has included the materials most

susceptible to corrosion in the CCCW environment within the scope of the One-Time Inspection

Program.

The applicant also stated that the scope of the One-Time Inspection Program includes carbon

steel, cast iron, and copper alloy components in a CCCW environment, including heat

exchanger components, to verify the effectiveness of the Water Chemistry Control Program in

managing the loss' of material due to corrosion. The applicant deemed that one-time

inspections for stainless steel components in a CCCW environment were unwarranted because

of the inherent corrosion resistance of stainless steel and the controlled CCCW environment

(discussed in the response to RAI 3.3-10).

The applicant indicated that it has performed numerous inspections, both visual and eddy

current, on heat exchangers in the CCCW environment. These inspections have not identified

any significant age-related degradation from corrosion or cracking. In addition, FNP has'an

ongoing effort to visually inspect selected CCCW system components when they are opened

for maintenance. The applicant claimed that these visual examinations have consistently

shown no significant corrosion or other age-related degradation for the CCCW environment.

The applicant stated that its operating experience, review for the LRA identified loss of material'

due to wear for the component CCW heat exchanger, tubes. Wear has occurred at the tube-tosupport plate interface in the vicinity of the shell-side (CCCW) inlet and outlet. This wear has

been attributed to flow-induced vibration of the tubes. In addition to plugging of tubes and

operational changes, corrective actions include ongoing ECT of the heat exchanger tubes as

part of the Service Water Program.

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The applicant clarified that to minimize confusi6n, the Service Water Program was associated

only with the service water sid6 of the CCW heat exchanger tubes in the LRA (Table 3.3.2-5).

However, the applicant also credited the Service Water Program with aging management of the

CCCW side of the tubes for loss of material due to wear.

The applicant concluded that the plant-specific operating experience confirms that the aging

management strategies described are adequate to manage applicable aging effects through

the period of extended operation.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3-15 and found the response to be

reasonable and acceptable because the applicant clarified that the Water Chemistry Control

Program managed all heat exchanger components in contact with CCCW as provided in the

LRA 3.3.2-xx series of tables, and because the applicant included the materials most,"

susceptible to corrosion in the CCCW environment within the scope of the One-Time Inspection

Program.

Applicable Aging Effects Requiring Management for Bolting in Auxiliary Systems (RAI 3.3-16)

The LRA does not identify cracking as an applicable AERM for bolting in auxiliary systems. In

LRA Table 3.3-1, lterm 24 states that cracking is not applicable to bolting because of material

selectidn'and sound maintenance practices'(control of torque, proper lubricants, and sealing

compounds); however, the susceptibility to cracking depends primarily on the bolting material

and the operating temperature. To deterriine that cracking is not an applicable AERM, by letter

dated March 8, 2004, in RAI 3.3-16, the staff asked the applicant to identify the bolting

materials and the yield strength of the bolting procured for the auxiliary systems within the

scope of license renewal and the operating temperatures of the bolting. For high-strength

bolting' (yield strength greater than 150 ksi), the staff also asked the applicant to provide

additional justification for the conclusion thatbcracking is not an applicable AERM, or to provide

an appropriate AMP to manage cracking.

The applicant initially responded to RAI 3.3-16 in a letter dated April 7,2004. However, in order

to address additional bolting materials utilized in the auxiliary systems, by letter dated May 28,

'2004, the applicant'provided a revised response which supersedes the SNC Letter No. NL-04-

0473 dated April 7, 2004. -

In its'revised response, the applicant stated that stainless steel, carbon steel, alloy steel, and

brass bolting 'materials used in FNP auxiliary systems within the scope of license renewal -

typically have low operating temperatures, however, some applications (e.g., portions of the

chemical volume control and sampling system) can operate at temperatures as high as RCS

temperatures. ' -,

The bolting materials used in the FNP auxiliary systems bolted connections include the

following: ' - ;; >:'- ;, 2

ASME SA-1 93 and ASTM Al 93 Grade B8 (Type 304) stainless steel bolts with a

minimum specified yield strength of 30 ksi

'3-197
IN

* ASME SA-1 93 and ASTM Al 93 Grade B6 stainless steel bolts with a minimum specified

yield strength of 85 ksi

* ASME SA-453 Grade 660 stainless steel bolts with a minimum specified yield strength

of 85 ksi

* ASME SA-307 and ASTM A307 Grade B carbon steel bolts with a maximum specified

tensile strength of 100 ksi

* ASME SA-1 93 and ASTM Al 93 Grade B7 alloy steel bolts with specified minimum yield

strengths up to 105 ksi

* ASTM B-1 6 brass studs

ASME SA-193 and ASTM A193 Grade B8 stainless steel bolts are used in applications in the

OCCW system, CCCW system, control room area ventilation system, primary containment

ventilation system, potable and sanitary water system, and reactor makeup water storage

system. Because of the low operating temperatures in these systems, these bolts are exposed

to operating temperatures well below the 140 OF threshold above which SCC is a concern for

stainless steels. These bolts are not high-strength bolts.

ASME SA-193 and ASTM Al93 Grade B6 stainless steel bolts are used in applications in the

reactor makeup water storage system. Because of the low operating temperatures in this

system, these bolts are exposed to operating temperatures well below the 140 OF threshold

above which SCC is a concern for stainless steels. These bolts are not high-strength bolts.

ASME SA-453 Grade 660 stainless steel bolts are used in applications in the reactor makeup

water storage and liquid waste and drains systems. Because of the low operating temperatures

in these systems, these bolts are exposed to operating temperatures well below the 140 OF

threshold above which SCC is a concern for stainless steels. These bolts are not high-strength

bolts.

ASME SA-453 Grade 660 stainless steel bolts are also used in applications in the chemical and

volume control system., These bolts are not high-strength bolts. Depending on the location of

specific components, closure bolting in this system could routinely be exposed to temperatures

greater than the 140 OF threshold above which SCC is a concern for stainless steels. Austenitic

stainless steels are susceptible to SCC when exposed to a corrosive environment that contains

aggressive chemical species and moisture and has a material temperature greater than 140 -OF.

At FNP, the concentration of contaminants in the inside and containment atmosphere -

environments is not significant because of the lack of sources of contaminants. The

atmosphere is therefore extremely mild in terms of corrosion effects for stainless steels, even in

areas of high humidity. Standard plant maintenance practices minimize the introduction of --

contaminants (e.g., chemical product controls), cleanliness controls, and wetting of components

(e.g., corrective maintenance to eliminate leaks). These factors effectively control corrosiveenvironments, eliminating SCC as an AERM for stainless steel bolts in the chemical volume and

control system. Plant operating experience confirms that SCC of bolting is not occurring at

FNP.

ASME SA-307/ASTM A307 Grade B carbon steel bolts are not considered high-strength bolting

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since'the upper limit on tensile stren'gth of 100 ksi assures that the imaximum bolt yield strength

will be less than 100 ksi. Based on this yield strength, these bolts are not susceptible to SCC in

normal PWR environ'rments. Both FNP and industrywide operating experience support this

conclusion.' - .

ASME SA-193/ASTM A193 Grade B7 bolts have a minimum specified yield strength of 105 ksi,

which is well below' the threshold value of 150 ksi. Bolting fabricated in accordance with

SA-1 93 could reasonably be expected to have an actual yield strength less than 150 ksi.

However, since no maximum yield strength is specified for this material, it cannot be assured

that the actual yield strengthfwill not exceed the 150 ksi limitation for SCC susceptibility set by

'the staff. The applicant asserted that several mitigating factors exist which, when considered:

together, indicate that SCC of ASME SA-1 93/ASTM Al 93 Grade B7 bolts is not an AERM at

FNP.

iThe applicant also stated that, although there have been isolated instances of SCC of bolting in

'the industry, these failures primarily resulted from of high-yield stress materials (including

abnormally high yield stresses resulting from improper heat treatment), excessive bolt preload,

and contaminants, such as the use of thread lubricants containing molybdenum sulfide (MoS2).

A review of industry'failure databases and NRC generic communications supports the position

that a combination of material selection, control of contaminants, and proper. maintenance and

torquing procedures is effective in eliminating the potential for SCC of bolting materials. These

practices are in place at FNP as discussed below:

* material selection-EPRI NP-5769, "Degradation of Bolting in Nuclear Power Plants,"

April 1988, indicates that susceptibility to SCC is minimized through selection of.

materials having specified minimum yield'strengths less than 150.ksi.- The auxiliary

systems bolting materials meet this criteria. 'ASME SA-1 93/ASTM Al 93 Grade B7 bolts

have a minimum specified yield strength of 105 ksi, which is below the recommended

value of 150 ksi.

control of contaminants-In general, environmental conditions that could lead to SCC of

bolting are not expected to occur in non-Class 1 components. Most bolting at FNP is

normally in a dry environment and coated with a lubricant. For bolting located outdoors,

the atmosphere is mild in terms of corrosive contaminants (a rural environment remote

from coastal regions). Rain tends to wash off contaminants instead of concentrating,

*them. Within'the industry, SCC failures of quenched and tempered alloy steel bolting,-

such as SA-1 93 Grade B7 bolts, have often been associated with the use of lubricants

that may decompose into SCC-inducing contaminants, most notably MoS2. -The ;- -

applicant has not used lubricants containing MoS2 and has procedural controls in place

at FNP to prevent the use of lubricants containing potentially detrimental species such

as chlorides and sulfates. -

* control of bolt preload-Excessive bolt stresses have resulted in SCC failures in the

industry. Proper control of bolt preload through sound bolt torquing practices has been

shown to prevent excessive preload and thereby minimize the potential for SCC failures.

Procedural controls in place at FNP ensure the use of proper bolt torquing practices.

The applicant stated that it uses 'ASME B-16 brass studs in the control room area ventilation

system pressurization/filtration and'recirculation/filtration units to attach the filter media to the

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- . a

mounting frames. These components are internal to the filtration units, so they are, exposed to

an inside environment which is the same as the control room air. For these specific

components, the atmosphere is air conditioned and filtered. ASME B-16 brass is greater than

15 percent zinc. The SCC of copper alloys is associated with exposure to ammonia and:

ammonium compounds. At the relatively low operating temperatures in the FNP control room

area ventilation system, a high concentration of contaminants would be required to drive SCC

as an aging mechanism. The inside environment at FNP does not contain levels of ammonia or

ammonium compounds sufficient to drive SCC.

The applicant also noted that it has addressed the potential for SCC of bolting materials at FNP

in response to several industry communications, including NRC IE Bulletin 82-02, INPO SOER

84-5, and EPRI guidance documents. For FNP; the bolting materials used,

lubricant/contaminant controls employed,'and sound bolt torquing practices have been effective

in eliminating this aging effect. A review of recent FNP operating history performed for

development of the FNP LRA did not identify any instances of SCC in auxiliary systems bolting

(which includes ASTM SA-1 93/ASTM Al 93 Grade B7 fasteners). In addition, a review of recent

NRC generic communications did not identify any recent bolting failures attributable to SCC.

Therefore, the applicant concluded that cracking due to SCC is not an AERM for the stainless

steel, carbon steel, alloy steel, and brass bolting materials used in FNP auxiliary systems.

Staff Evaluation of the Applicant's Response

The staff reviewed the applicant's response to RAI 3.3-16 and found it to be reasonable and

acceptable because the applicant stated that, at FNP, the bolting materials used,

lubricant/contaminant controls'employed, and sound bolt torquing practices have been effective

in eliminating this aging effect.; A review of recent FNP operating history performed for

development of the FNP LRA did not identify any instances of SCC in auxiliary systems bolting

(which includes ASTM SA-1 93/ASTM Al 93 Grade 67 fasteners). In addition, a review of recent

NRC generic communications did not identify any recent bolting failures attributable to SCC.

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, identified under the

staff's general RAts on the AMR issues, that are not addressed by the GALL Report, so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.1 New Fuel Storage AMR Results

Summary of Technical Information in the Application

In Section 3.3.2.1.1 of the LRA, the applicant stated that it had evaluated new fuel storage as a

structural item as part of the auxiliary building in Section 3.5.2.1.2 of the LRA. The applicant

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noted that it used the Structural Monitoring Program to manage the AERMs for the new fuel

storage components and structure.

Staff Evaluation

The staff reviewed Section 3.3.2.1.1, "New Fuel Storage Aging Management Review Results,"

including the information provided in Item 3.3.1-11 of Table 3.3.1 of the LRA. Section 3.5.2.3.2

of this SER (discussed in the staff review related to the resolution of RAI 3.3-17) provides the

staff evaluation of LRA Section 3.3.2.1.1.

The staff finds that the applicant's AMR results for FNP's new fuel storage are consistent with

NUREG-1 801 and are therefore 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 new fuel storage

components that are not addressed by the GALL-Report, so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.2 Spent Fuel Storage AMR Results

Summary of Technical Information in the Application

In Section 3.3.2.1.2 of the LRA, the applicant stated that it had evaluated new fuel storage as a

structural item as part of the auxiliary building in Section 3.5.2.1.2 of the LRA. The applicant

noted that it used the Water Chemistry Control Program to manage the AERMs for the spent

fuel storage components and structure.

Staff Evaluation

The staff reviewed Section 3.3.2.1.2, "Spent Fuel Storage Aging Management Review Results,"

including the information provided in Item 3.3.1-13 of Table 3.3.1 of the LRA. Section 3.5.2.3.2

of this SER (discussed in the staff review related to the resolution of RAI 3.3-17) provides the

staff evaluation for LRA Section 3.3.2.1.2.

The staff finds that the applicant's AMR results for FNP's spent fuel storage are consistent with

NUREG-1801 and are therefore acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited with managing the aging effects, for the spent fuel

storage components that are not addressed by the GALL Report, so that the intended functions

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'I

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.3 Spent Fuel Pool Cooling and Cleanup AMR Review

Summary of Technical Information in the Application

In Section 3.3.2.1.3 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 spent fuel pool cooling and cleanup system:

* Water Chemistry Control Program

* One-Time Inspection Program

* External Surfaces Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-3 of the LRA, the applicant summarized the AMRs for the spent fuel pool cooling

and cleanup system components and identified which AMRs it considered to be consistent with

the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the spent fuel pool cooling and cleanup system components

relating to those combinations of components, materials, environments, and AERMs and found

them to be consistent with the GALL Report. These combinations use notes A through E in

LRA Table 3.3.2-3. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the spent fuel pool cooling and cleanup system relating to those

combinations of components, materials, environments, and AERMs that the GALL Report does

not address. These combinations use notes F through J in LRA Table 3.3.2-3. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs with managing the AERMs. The staff also reviewed the applicable FSAR Supplements

for the AMPs to ensure that the program descriptions are adequate.

Aging Effects

Table 2.3.3.3 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 an AMR

include heat exchanger (channel head), heat exchanger (tubesheet), heat exchanger (tubes),

piping, pump casings, and valve bodies.

For these component types, the applicant identified stainless steel components in borated water

and closed-cooling water environments as subject to the aging effect of loss of material.

However, stainless steel components exposed to an inside environment experience no aging

effect.

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The staff reviewed the information in Section-2.3.3.3, Table 2.3.3.3, Section 3.3.2.1.3, and

Table 3.3.2-3 of the LRA.- The staff 'determined that it needed additional information to

complete its review. - -

The staff organized its RAls into general RAls and system-specific RAls. The general RAls

applicable to this system include'RAls 3.3-9,;3.3-'10, and 3.3-15. -There are no relevant systemspecific RAls. -

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-9,;3.3-10, and 3.3-15. By letter dated April 7,

2004, the applicant responded to these RAls. Section 3.3.2.3.0 of this SER describes these

RAls, the applicant's responses, and the staff's evalutation of the responses. -

On the b-asis'of its review of the LRA and the'additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects of the spent fuel pool cooling

and cleanup system component types that are not addressed by the GALL Report are -. consistent with industry experience for these material-environment combinations. The staff did

not identify any omitted aging effects. Therefore, the staff finds that the applicant has identified

the appropriate aging effects for the materials-and environments associated with the above

components in the spent fuel pool cooling and cleanup system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified .7

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program. - .

Table'3.3.2.3 of the LRA identifies the Wateir Chemistry Control Program (Appendix B.3.2) as

managing the aging effects described above forthe spent fuel pool cooling and cleanup

system.

The applicant credited the Water Chemistry Control Program with managing the loss of material

aging effect on the stainless steel piping and valve bodies exposed to borated water and

treated water (including-CCCW). DuWring its'review,-the staff determined that it needed - -:

additional information to complete its evaluation -and issued RAI 3.3-10. 'Section 3.3.2.3.0

describes RAI 3.3-10, the applicant's response to this RAI, and the staff's evaluation of the

responses.

The staff's detailed review of this AMP appears in Section 3.0.3.2.1 of this SER. - -- ,!ie

On the basis'of its review of the information'provided in the LRA, the staff finds that the - -

applicant has identified appropriate AMPs for managing the aging effects of the spent fuel pool

cooling and cleanup system component types that the GALL Report does not address. In

addition, the staff finds the program descriptions in the FSAR Supplement acceptable.

Conclusion ' '

On the basis of its review, the staff concludes that the applicant has adequately identified the

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aging effects, and the AMPs credited with managing the aging effects, for the spent fuel pool

cooling and cleanup system components that the GALL Report does not address, so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.4 Overhead Heavy and Refueling Load Handling System AMR Review

Summary of Technical Information in the Application

In Section 3.3.2.1.4 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 overhead heavy and refueling load handling system:

* Structural Monitoring Program.

* Overhead and Refueling Crane Inspection Program

In Table 3.3.2-4 of the LRA, the applicant summarized the AMRs for the overhead heavy and

refueling load handling system components and identified which AMRs it considered to be

consistent with the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the overhead heavy and refueling load handling system

components relating to those combinations of components, materials, environments, and

AERMs and found them to be consistent with the GALL Report. These combinations use notes

A through E in LRA Table 3.3.2-4. Section 3.3.2.1 of this SER documents the staff's

evaluation.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified th~e

aging effects, and the AMPs credited with managing the aging effects, for the. overhead heavy

and refueling load handling system components that are addressed by the GALL Report, so ;

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited with managing aging in these components, as

required by 10 CFR 54.21 (d).

3.3.2.3.5 Open-Cycle Cooling Water System

Summary of Technical Information in the Application

In Section 3.3.2.1.5 of the LRA, the applicant identified the materials, environments, and

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AERMs. The applicant identified the following programs that manage the aging effects related

to the OCCW system:

* Service Water Program

Water Chemistry Control Program

* --One-Timie Inspection Program

* External Surfaces Monitoring Program

* Buried Piping and Tank Inspection Program

* : Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-5 of the LRA, the applicant summarized the AMRs for the OCCW system

components and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed dthbeAMRs of the OCCW system components relating to those combinations

of cobiponents, 'materials, environments, and AERMs and found them to be consistent with the

GALL Report. These combinations' A' through E in LRA Table 3.3.2-5. Section

3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the OCCW system relating to those combinations of

components, materials, environments ,and AERMs that the GALL Report does not address.

These combinations use notes F througlh ins LRA Table 3.3.2-5.' The'staff determined that the

applicant has identified all applicable AERMs and has credited appropriate AMPs for managing

the AERMs. The staff also reviewed the applicable FSAR Supplements for the AMPs to ensure

that the program descriptions are adequate.

Aging Effects

Table 2.3.3.5 of the LRA lists individual'systern 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 the'air compressor lube oil cooler (channel head, shell, tubes/tubesheet), air

compressor intercooler, aftercooler,'nd blegd-6ff'air cooler (channel head, shell, ;

tubes/tubesheet), closure bolting, containrmn't arid Engineered safety feature room coolers

(channel head and tubes), flow orifice/element, piping, piping with guard pipe, lube and cooling

water pump casings, strainers (shell), and valve bodies.

For these component types, the applicant'identified the following materials, enviroriments, and

AERMs: -

* ' In an air/gas (wetted) environment, stainless'steel and carbon steel components are

subject to the aging effect of loss of material.

* Carbon'steel components in air/gas&6n~vironrnents are also'subject to loss of material. :

* Stainless steel components in a buried environment are subject to the aging effect of

loss of material. ' ' -

* Carbon steel components in an embedded environment have no applicable aging

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I

effects.. --

* Stainless steel components exposed to inside, outside, or lube oil environments

experience no aging effects.

* In an inside environment, copper alloy and cast iron components experience no aging

effects.

The staff reviewed the information in Section 2.3.3.5, Table 2.3.3.5, Section 3.3.2.1.5, and

Table 3.3.2-5 of the LRA. During its review, the staff determined that it needed additional

information.

The staff organized the RAls into general RAls and system-specific RAls. General RAis

applicable to this system include RAls 3.3-9, 3.3-14, and 3.3-16.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-9, 3.3-14, and 3.3716.. By letter dated April 7,

2004, the applicant responded to these RAls. Section 3.3.2.3.0 describes these RAls, the

applicant's responses, and the staff's evaluation of the responses.

By the same letter dated March 8, 2004, the staff asked the applicant to provide additional

information on the issues described in the system-specific RAI 3.3.2.1.5-1. . By letter dated April

7, 2004, and as revised by its letter dated March 3, 2005, the applicant responded to this RAI.

The following describes RAI 3.3.2.1.5-1, the responses to this RAI, and the staff's evaluation of

the responses.

Buried Stainless Steel Piping Not Included in the Scope of the Buried Piping and Tank

Inspection Program (RAI 3.3.2.1.5-1). The LRA states that the applicant uses the Buried Piping

and Tank Inspection Program to manage buried carbon steel and buried stainless steel piping

in this system. However, the scope of the Buried Piping and Tank Inspection Program includes

only buried carbon steel piping and tanks. The staff asked the applicant to clarify which AMP it

will use to manage the buried stainless steel piping. If it will use the Buried Piping and Tank

Inspection Program, the applicant should provide the appropriate updates to the 10 elements or

explain how it will use the GALL program for stainless steel components.

In response, by letter dated April 7, 2004, and as revised by letter dated March 3, 2005, the

applicant stated that in addition to buried carbon steel piping and tank components, the Buried

Piping and Tank Inspection Program will manage aging in the buried stainless steel and buried

copper alloy piping components (fire protection system, LRA Table 3.3.2-13). The applicant

agreed that the scope of this program should have included buried stainless steel and copper

alloy piping components. The applicant stated that it has updated the Buried Piping and Tank

Inspection Program to include buried stainless steel and copper alloy piping components.

The applicant corrected FNP's LRA Appendix A.2.16 and Appendix B.5.4 as follows (changes

are in bold italics):

LRA Appendix A.2.16-Buried Piping and Tank Inspection Program

The new Buried Piping and Tank Inspection Program will be used to manage the loss of material from

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external surfaces of In-scope pressure-retaining buried carbon steel piping and tanks and buried

stainless steel and copper alloy piping during the extended period of operation. Administrative controls

and procedures will be put ini place to ensure that builed piping and tanks will be Inspected when they are

excavated for maintenance or when those compo'hents are exposed for any reason. This new program will

be implemented prior to the period of extended op6ration.

This program will be consistent with the 10 attributes of the aging management program described in

NUREG-1 801, Section XL.M34, with the exception that it also includes provisions for inspection of buried

stainless steel and copper alloy piping.

LRA Appendix 6.5.4-Buried Piping and Tank Inspection Program

B.5.4.1 Program Description ,

The new FNP Buried Piping'and Tank Inspection Program will be used to manage loss of material frorii the

external surfaces of pressure-retaining buried carbon steel piping and tanks and buried stainless steel.

and copperpiping components. Preventive measures have been put in place in accordance with -

standard industry practices for external coatings and wrappings. Buried piping and tanks will be inspected

when they are excavated for maintenance or when those components are exposed for any reason. FNP

will implement this new program prior to the period of extended operation. '

The scope of the FNP Buried Piping and Tank Inspection Program includes the external surfaces of the

following buried components:

* Service water piping

-* ' Emergency diesel generator fuel oil storage tanks and fuel oil transfer piping

* Fire protection piping , :

: - - Oil-static Cable Pressurization System buried components from the high voltage

to the low voltage switchyard

B.5.4.2 NUREG-1801 Consistency

The FNP program attributes will be consistent with those described in NUREG-1801, Chapter XI.M34

except as described In B.5.4.3.

B.5.4.3 Exceptions to NUREG-1801

Buried stainless steel and copper alloy piping components are also Included In the scope of the

program. The burled stainless steel and copper alloy components are not normally wrapped or

coated, however, these materials have a natural resistance to corrosion In the buried environment

Inspections are performed when the components are excavated for maintenance or for any other

-reason Including investigatlon'of a potential leak.

For uncoated/unwrapped piping, visual lnspection will also be used to examine the external

surfaces to confirm that no loss of material has occurred.

Loss of material in piping will be reported and evaluated according to site corrective actions

procedures.

B.5.4.4 Enhancements

* None (This Is a new program.)

B.5.4.5 Operating Experience

This is a new program. Therefore, no programmatic operating experience has been gained. Leaks in

buried piping systems at FNP have typically resu6lted from localized damage to the'extemal

coating/wrapping on carbon steel piping, such as from a rock or mechanical damage during installation.

FNP has been successful at detecting these leaks prior to any loss of system function.

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B.5.4.6 Conclusion

Implementation of the new FNP Buried Piping and Tank Inspection Program prior to the period of extended

operation will provide reasonable assurance that the effects of aging on the pressure-retaining function of

those components will be maintained during the period of extended operation.

The staff reviewed the applicant's response to RAI 3.3.2.1.5-1 and found the response to be

reasonable and acceptable because the applicant updated the Buried Piping and Tank

Inspection Program to include buried stainless steel and copper alloy piping components and

provided the complete update of the AMP reflecting the changes.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects of the OCCW system

component types given above that the GALL Report does not address are consistent with

industry experience for these material-environment combinations: 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

OCCW system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR 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 OCCW system:

* One-Time Inspection Program (Appendix B.5.5)

* Buried Piping and Tank Inspection Program (Appendix B.5.4)

The applicant uses the One-Time Inspection Program to manage several different AERMs.

The staff reviewed the utilization of the One-Time Inspection Program for these different

combinations of materials, environments, and AERMs for the components in the OCCW system

and finds that this AMP is adequate for managing the identified aging effects because these

aging effects are expected to occur at a relatively slow rate.

However, during its review, the staff determined that it needed additional information to

complete its evaluation and issued RAI 3.3.2.1.5-1. This RAI, the applicant's responses to this

RAI, and the staff's evaluation of the responses are described earlier in this section of the SER.

The staff's detailed review of these AMPs appears in Section 3.0.3.1 of this SER.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the RAls, the staff finds that the applicant has identified appropriate AMPs for

managing the aging effects of the OCCW system compon ent types that the GALL Report does

not address. In addition, the staff finds the program descriptions in the FSAR Supplement

acceptable.

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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 ma'naging the aging effects, for the OCCW system

components that are not addressed by'the"GALL-Rebiort, so that the'intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21(a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).'

3.3.2.3.6 Closed-Cycle Cooling Water System

Summary of Technical Information in the Application'

In Section 3.3.2.1.6 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 CCCW system:

* Water Chemistry Control Program " ' ' .

* One-Time Inspection Program External Surfaces Monitoring Program -

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-6 of the LRA, the applicant sufrniarized the AMRs for the CCCW system'-

components and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the CCCW system components relating to those combinations

of components, materials, environments, and AERMs and found them to be consistent with the

GALL Report. 'These combinations use nojes'A throiugh E in LRA Table 3.3.2-6. Section

3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the CCCW system relating to those combinations of

components, materials, environments, and AERMs that the GALL Report does not address.

These combinations use notes F through J in LRA Table 3.3.2-6.- The staff determined that the

applicant has identified all applicable AERMs aiid hascredited appropriate AMPs with

managing the AERMs. The staff also reviewed the applicable FSAR Supplements for the

AMPs to ensure that the program descriptions are adequate.

Aging Effects

Table 2.3.3.6 of the LRA lists individual sjyttemi components within'the scope of license renewal

and subject to an AMR. The cormnponent types that do'nbt'rely'o'nthe GALL Report for AMR'

include closure bolting, flow orifice/element, reactor coolant drain tank heat exchanger (tubes

and tubesheet), 'piping, -and valve bodies'

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For these component types, the applicant identified the following materials, environments, and

AERMs that do not rely on the GALL Report for AMR:

* Stainless steel components in closed-cooling water and borated water environments are

subject to the aging effects of loss of material and cracking.

* Stainless steel components exposed to an inside environment experience no aging

effects.

The staff reviewed the information in Section 2.3.3.6, Table 2.3.3.6, Section 3.3.2.1.6, and

Table 3.3.2-6 of the LRA. During its review, the staff determined that it needed additional

information.

The staff organized the RAls into general RAls and system-specific RAls. General RAls

applicable to this system include RAls 3.3-9, 3.3-10, 3.3-15, and 3.3-16. There are no relevant

system-specific RAls.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-9, 3.3-10, 3.3-15, and 3.3-16. By letter dated

April 7, 2004, the applicant responded to these RAls. Section 3.3.2.3.0 of this SER describes

these RAls, the applicant's responses, and the staff's evaluation of the responses.

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 RAIs, the staff finds that the aging effects of the

CCCW system component types that the GALL Report does not address are consistent with

industry experience for these material-environment combinations. 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

CCCW system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-6 of the LRA identifies the Water Chemistry Control Program (Appendix B.3.2) asmanaging the aging effects described above for the OCCW system. Section 3.0.3.2.1 of this

SER includes the staff's detailed review of this AMP.

The applicant credited the Water Chemistry Control Program with managing the loss of material

aging effect on the stainless steel components exposed to borated water or treated water

(including closed-cooling water). During its review, the staff determined that it needed

additional information and issued RAI 3.3-10. Section 3.3.2.3.0 of this SER describes this RAI,

the applicant's responses, and the staff's evaluation of the responses.

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

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identified appropriate AMPs for managing the aging effects of the OCCW system component

types that are not addressed by the GALL Report. In addition, the staff finds the program

descriptions in the FSAR 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 CCCW system

compon'ents that are not addressed by the GALL' Report, so that the intended funictions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3). .

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.3.2.3.7 Compressed Air System

Summary of Technical Information in the Ap6lication

In Section 3.3.2.1.7 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 compressed air system:

* One-Time Inspection Program

* External Surfaces Monitoring Program

Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-7 of the LRA,lthe applicant summarized the AMRs for the compressed air system

components and identified which AMRs it'considejed t6 be consistent with the GALL Report.

Staff Evaluation

The staff'reviewed the AMRs of the compressed'air system components relating to those

combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These 'combinations use notes A thr-ough E in LRA Table'

3.3.2-7. Section 3.3.2.1 of this SER do'6cumets ihe staff's evaluation.

The staff reviewed the AMR of the compressed air system relating to those combinations of

components, materials, environments, and AERMs that the GALL Report does'not address.

These combinations use notes F through J in LRA Table 3.3.2-7. The- staff determined that the

applicant has identified all applicable AERMs and has credited appropriate AMPs with

managing the'AERMs. The staff also reviewed the' applicable FSAR Supplements for the

AMPs to'ensure that the program descriptions'areadeqnuate.'''

. . . ... . . .

Aging Effects ' ' - -- . , - .,.,..

Table 2.3.3.7 of the LRA lists individual system components within the scope of license renewal

and subject to n AMR. The component types that do not rely on the GALL Report for an AMR

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I _ _ N

include air accumulators, filters (casing), piping, fluid traps, and valve bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Copper alloy, aluminum, and galvanized steel components in an air/gas (wetted)

environment are subject to the loss of material.

* Copper alloy and stainless steel components in dried gas and inside environments

experience no aging effects.

* Aluminum components in an inside environment and carbon steel components in a dried

gas environment have no aging effects.

The staff reviewed the information in Section 2.3.3.7, Table 2.3.3.7, Section 3.3.2.1.7, and

Table 3.3.2-7 in the LRA. During its review, the staff determined that it needed additional

information.

The staff organized the RAIs into general RAIs and system-specific RAIs. The general RAls

applicable to this system include RAIs 3.3-9 and 3.3-13.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-9 and 3.3-13. By letter dated April 7, 2004, the

applicant responded to these RAls. Section 3.3.2.3.0 of this SER describes these RAls, the

applicants responses, and the staff's evaluation of the responses.

By the same letter dated March 8, 2004, the staff asked the applicant to provide additional

information on the issues described in the system-specific RAI 3.3.2.1.7-1. By letter dated April

7, 2004, the applicant responded to this RAI. The following describes RAI 3.3.2.1.7-1, the

responses to this RAI, and the staff's evaluation of the responses.

Justification for the Use of the One-Time Inspection Program in an Air/Gas (Wetted)

Environment (RAI 3.3.2.1.7-1). The LRA credits the One-time Inspection Program (B;5.5) with

managing the aging effect of loss of material of several components in an air/gas (wetted)

environment. The staff notes that one-time inspections are used for verification when

significant aging is not expected.. The staff also observes that for comparable components,

materials, environments, and AERMs in the compressed air system, the GALL Report

recommends the use of GALL AMP XI.M24, uCompressed Air Monitoring," which uses, in part,

periodic inspection and testing of components. The staff asked the applicant to justify the use

of a one-time inspection in lieu of periodic inspection and testing of components for the

compressed air system components in an air/gas (wetted) environment.

In response, by letter dated April 7, 2004, the applicant stated that it will use the new FNP OneTime Inspection Program for cases where either (1) an aging effect is not expected to occur but

data are insufficient to completely disprove the effect, or (2) an aging effect is occurring slowly

enough that it will not affect the component or structure intended function during the period of

extended operation, and therefore it does not require additional aging management.

The applicant also stated that the One-Time Inspection Program will provide for an inspection

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of a sampling of compressed air system components upstream of and including the air dryers to

determine if any significant corrosion is occurring within these c6mpobnents. Low points in this

portion of the system are routinely drained to prevent moisture accumulation. Loss of material

is expected to occur slowly enough that it will not affect the component intended function during

the period of extended operation. The program includes an evaluation to determine the need

for followup examinations to monitor the progression of any aging degradation found during the

inspection.'

The applicant noted that in the past, the NRC has accepted one-time inspections in similar

environments at the V.C. Summer and Robinson nuclear plants.

The staff reviewed the applicant's response to RAI 3.3.2.1.7-1 and found the response to be

reasonable and acceptable because the applicant clarified that the new FNP One-Time

Inspection Program will be used for cases where either (1) an aging effect is not expected to

occur but the data is insufficient to completely disprove the effect, or (2) an aging effect is

occurring slowly enough that it will not affect the component or structure intended function

during the period of extended operation, and therefore it does not require additional aging

management. The applicant also noted that the NRC has accepted one-time inspections in

similar environments at the V.C. Summer and Robinson nuclear plants. - -

During the scoping review, in a response to RAI 2.3.3.7-4 dated April 22, 2004, the applicant

added the stainless steel strainers (element) to Tables 2.3.3.7 and 3.3.2-7. The applicant.

stated that the One-Time Inspection Program will manage the aging effect of loss of material of

the stainless steel strainers exposed to an air/gas (wetted) environment. The staff finds the

applicant's response to RAI 2.3.7-4 to be reasonable and acceptable because significant aging

is not expected for stainless steel components exposed to an air/gas (wetted) environment.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds the aging effects of the above compressed air

system component types that are not addressed by the GALL Report to be consistent with

industry experience for these material-environment combinations: 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

compressed air system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program. - - -i' -

Table 3.3.2-7 of the LRA identifies the One-Time Inspection Program (Appendix B.5.5) to

manage the aging effects described above for the compressed air system.

The applicant uses the One-Time Inspection Program for managing several different AERMs.

The staff reviewed the utilization of the One-Time Inspection Program for these different

combinations of materials, environments, and AERMs for the components in the compressed

air system and finds this AMP adequate for managing the identified aging effects because

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these aging effects are expected to occur at a relatively slow rate.

Section 3.0.3.1 of this SER provides the staff's detailed review of this AMP.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified appropriate AMPs for managing the aging effects of the compressed air

system component types that the GALL Report does not address. In addition, the staff finds

the program descriptions in the FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMP credited with managing the compressed air system components

that are not addressed by the GALL Report, so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMP credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.8 Chemical and Volume Control System

Summary of Technical Information in the Application

In Section 3.3.2.1.8 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 chemical volume and control system:

* Water Chemistry Control Program

* One-Time Inspection Program

* External Surfaces Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-8 of the LRA, the applicant summarized the AMRs for the chemical volume and

control system components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the chemical volume and control system components relating

to those combinations of components, materials, environments, and AERMs and found them to

be consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-8. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the chemical volume and control system relating to those

combinations of components, materials, environments, and AERMs that the GALL Report does

not address. These combinations use notes F through J in LRA Table 3.3.2-8. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

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AMPs for managing'the AERMs. The staff aiso'reviewed the applicable FSAR Supplements for

the AMPs to ensure'that the prograim descriptionsar'e adequate."'

Aging Effects

Table 2.3.3.8 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 regenerative heat exchanger (channel heads, shells,'tubes/tubesheet), letdown, excess

letdown,' and RCP seal water heat exchangers (channel head and tubesitubesheet), boron ;

thermal regeneration' chiller (channel head,' tubes/tubesheet), boron 'the'rmal regeneration'

moderating and reheat heat exchanger (channel head and shell, tubes/tubesheet), '

demineralizers (pressure-retaining components), closure bolting, filters (casing), letdown

orifices, piping, boric acid transfer pump casings, boric acid tanks, volume control tank, and

valve bodies.

For these component types, the applicant identified the following materials, environments; anid

AERMs:

* CASS components in a borated water environment are subject to the loss of material.

* Stainless steel components in closed-cooling' water and borated water environments are

subject to the aging effect of loss of material.

* - Stainless steel and CASS compornents exposed to an inside environrrient experience no

aging effects.

* Stainless steel components in air/gas, dried or wetted (with no oxygen), have no aging

eff ects.

The staff reviewed the information in Section 2.3.3.8, Table 2.3.3.8, Section 3.3.2.1.8, and

Table 3.3.2-8 in the LRA. During its review, th6 staff determined that it needed additional

information.

The staff organized its RAls into general RAls and system-specific RAls. General RAls

applicable to this system include RAls 3.3-9, 3.3:10,3.3-15, and 3.3-16.

,By letter dated March 8, 2004, the staff asked the applicant to provide additional in frmation on

the issues described in RAis 3.3-9, 3.3-10, 3.3-15, and 3.3-16. By letter dated April 7, 2004,

the applicant responded to these RAls. Sectioni 3.3.2.3.0 describes these RAls, the applicant's

responses, and the staff's evaluation of the responses.

By the same letter dated March 8, 2004, the staff requested the applicant to provide additional

inforrmation on the issues described in the systemn-specific RAls 3;3.2.1.8-1 and 3.3.2.1.8-2. 'By

letter dated April 7,' 2004, the applicant'respond6d to these RAls. The following des6ribes RAls

3.3.2.1.8-1 and 3.3.2.1.8-2, the responses to these RAls, and the staff's evaluation of the

responses.

Applicable Apinq Effect for Cast Austenitic Stainless Steel Components in Hiph-TemDerature

Borated Water Environment (RAI 3.3.2.1.8-1). The loss of fracture toughness/thermal aging'

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-- I -

embrittlement may be an applicable aging effect for CASS components in a high-temperature

borated water enviroriment. Thestaff asked the applicant to clarify whether this is an applicable

aging effect for the CASS components (such'a-s the regenerative heat exchanger) in the

chemical volume and control system and, if it is, the staff asked the applicant to provide an

AMP.

In response, by letter-dated Ap'ril 7, 2004, the'applicant stated that only components operating

at temperatures exceeding 482 0F need to be screened for susceptibility to thermal

embrittlement. Within the chemical volume and control system, the only austenitic stainless

steel castings meeting this operating temperature requirement are the regenerative heat

exchanger shells and channel heads.

The applicant further stated in a May 19, 2000, letter from Mr. C.l. Grimes (NRC) to Mr. D.J.

Walters (NEI), "License Renewal Issue No. 98-0030, Thermal Aging Embrittlement of Cast

Austenitic Stainless Steel Components," that the staff evaluation outlined an acceptable method

for screening CASS components for susceptibility to thermal embrittlement. The applicant

applied the screening criteria contained in this staff guideline to the chemical volume and

control system regenerative heat exchanger shells and channel heads. These castings were

determined to be low in molybdenum content (less than 0.5 percent by weight) and to be

centrifugally cast The applicant' determined that, according to the screening criteria contained

in Table 2 of the staff guideline, these castings are not susceptible to thermal embrittlement,

regardless of casting ferrite nriiber.

The staff reviewed the applicant's response to RAI 3.3.2.1.8-1 and found the response to be

reasonable and acceptable because the applicant based its cornclusion on the screening criteria

contained in Table 2 of the staff guideline outlined in the May 19, 2000, letter.

Stainless Steel Boric Acid Tanks in Air/Gas (Air Srace) Environment (RAI 3.3.2.1.8-2). For

stainless steel boric acid tanks in an air/gas (air space) environment, the staff asked the

applicant to clarify whether the interior surface of the tank is subject to periodic drying and

wetting because of fluid level changes. If so, the applicant should clarify whether this may lead

to a concentrated level of boric acid, leading in turn to aging degradation, and should provide,

information on how to manage this aging effect.

In response, by letter dated April 7, 2004, the applicant stated that the chermical volume and

control system boric acid'tanks utilize a bladder'and loop seal design to prevent the ingress of

oxygen into the chemical volume and control system. Therefore, fluid. level changes do not

result in the type of periodic w~et/dry cyclinrg that potentially could produce concentrated levels of

boric acid. Because of the bladder, the air space of the boric acid tanks is not exposed to

wetting with borated water.

Additionally, the applicant stated-that the FNP chemical volume and control system boric acid

tanks are fabricated from 300-series wrought austenitic stainless steels. Industry material

screening tests indicate that this material is relatively unaffected by exposure to boric acid, boric

acid spray, and boric acid crystals.

The staff reviewed the applicant's response to RAI 3.3.2.1.8-2 and found the response to be

reasonable and acceptable because the applicant uses a bladder and loop seal design in the

chemical volume and control system boric acid tanks to prevent ingress of oxygen into the

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chemical volume and control system and uses 300-series wrought austenitic stainless steels,

which are relatively unaffected by exposure to boric acid, as fabrication materials for these

tanks. . . . -

During the scoping' review, in a supplemental response (Part 2) to RAI 21 -1 dated June 4,

2004, the applicant added the stainless steel tanks (boron' concentration meter tanks and - chemical mixing tank) to Tables 2.3.3.8 and 3.3.2-8. The original LRA addresses most of the

aging effects and AMPs for the added cornponi~ts (e'.'g., boron &oncentration meter tanrks).

The applicant stated that the stainless steel chemical inixing tanks'anid the associated stainlesssteel piping and valves exposed to treated water (less than 140 °F) are subject to the loss of

material aging effect, and the Water Chemistry Control Program iahd One-Time Inspection:-

Program will manage this aging effect.''The staff findsthe applicant's supplemental response

(Part 2) to RAI 2.1-1 related to the chemical volume and control system to be reasonable and

acceptable because the identified aging effedts' will be adeqbately M anaged. :

As-a followup to SNC's response to RAi 2..3..23-1 provided in SNC Letter No. NL-04-0678

dated April 22, 2004, the staff requested SNC to' discuss whether disintegration of the

diaphragm membrane can cause blockage of the dspply lines from the' reactor makeup water

storage tanks to the COW system. in its response dated June 18, 2004, by SNC Letter No.

NL-04-1038, the applicant added "tank diaphragms (boric acid tanks)" to Tables 2.3.3.8 and

3.3.2-8.' The applicant indicated that elastomers exposed to treated water or'air/gas (tank air

space) are subject to change in material properties, cracking, and loss of material aging effects.

The applicant will use-a new AMP, Periodic Surveillarfce and Preventive Maintenance Activities

(B.5.9), to manage the aging effects mentioned above. The staff finds the applicant's followup

response to RAI 2.3.3.23-1 to be reasonabl6 and acceptable because this new'AMP will provide

for periodic component inspections and testinrg'to detect aging effects'or component

degradation before loss of intehded functions occurs.

On the basis of its review of the LRA and the additional information included in the applicant's'

response to the above RAts, the staff finds that the aging effects of the chemical volume and

control system component types given above that the GALL Report does not address are

consistent with industry experience for these material-environment combinations. The staff did

not identify any omitted aging effects. Therefore, the staff finds'that the applican6t has identified

the appropriate aging effects for the materials and environments' associated with the above

components in the chemical volume and cointrol system:'

Aging Management Programs

After evaluating the' applicant's identification of agirig 'effects'for each of the 'above components;

the staff reviewed the AMPS to deitrmineif thedare appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program. -, . . .1'I - I I.- -.11-' ; - -

Table 3.3.2-8 of the LRA and the applicant's followup response, dated June 18, 2004, to RAI

2.3.3.23-1 identify the following AMPs for mrnaginrgthe aging effects-described above for thechemical volume and control system:

* Water Chemistry Control Prograrm (Appendix B.3.2)

* One-Time Inspection Program (Appendix B.5.5)

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I aI

* Periodic Surveillance and Preventive Maintenance Activities (Appendix B.5.9)

The applicant credited the Water Chemistry Control Program with managing several different

AERMs. During its review, the staff determined that it needed additional information and issued

RAI 3.3-10. Section 3.3.2.3.0 of this SER describes RAI 3.3-10, the applicant's response to this

RAI, and the staff's evaluation of the responses.

The applicant uses the One-Time Inspection Program for managing several different AERMs.

The staff reviewed the utilization of the One-Time Inspection Program for these different

combinations of materials, environments, and AERMs for the components in the chemical

volume and control system and finds that this AMP is adequate for managing the identified

aging effects because these aging effects are expected to occur at a relatively slow rate.

The Periodic Surveillance and Preventive Maintenance Activities Program is a condition

monitoring program. It includes those preventive maintenance and 'surveillance testing

activities credited with managing the aging effects identified in the AMRs. The staff reviewed

the utilization of the Periodic Surveillance and Preventive Maintenanice Activities Program for

the boric acid tank diaphragm inspections for managing change in material properties, cracking,

and loss of material on the internal elastomer diaphragms in these tanks. The staff finds this'

AMP adequate because the applicant stated that the extent and schedule of inspections will

assure detection of component degradation before the loss of intended functions occurs.

Sections 3.0.3.2.1, 3.0.3.1, and 3.0.3.3.4 of this SER detail the staff's review of the AMPs.

On the basis of its review of the LRA and the additional infomiation included in the applicant's

response to the above RAls, the staff finds the applicant has identified appropriate AMPs for

managing the aging effects of the chemical volume and control system component types that

the GALL Report does not address. In addition, the staff finds the program descriptions in the

FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited with managing the aging'effects for the chemical volume

and control system components that are not addressed by the GALL Report, so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.9 Control Room Area Ventilation System

Summary of Technical Information in the Application

In Section 3.3.2.1.9 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs that manage the aging effects related

to the control room area ventilation system

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* One-Time Inspection Program

* - External Surfaces Monitoring Program

In Table 3.3.2-9 of the LRA, the applicant summarized the AMRs for the control room area

ventilation system components and identified which AMRs it considered to be consistent with

the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the control room area ventilation system components relating to

those combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-9. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the control room area ventilation system relating to thosecombinations of components, materials, environments, and AERMs that are not addressed in

the GALL Report. These combinations use notes F through J in LRA Table 3.3.2-9. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs for managing the AERMs. The staff also reviewed the applicable FSAR Supplemenits for

the AMPs to ensure that the program descriptions are adequate.

Aging Effects

Table 2.3.3.9 of the LRA lists individual system components within the scope of license renewal

and subject to an AMR. The components that do not rely on the GALL Report for an AMR

include closure bolting,'compressible joints and seals, cooling coils (HVAC refrigerant coils and

fins), ducts and fittings, equipment frames and housing, fire dampers (frames and housing

only), flexible connectors, piping, and valve-bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Elastomer components exposed to inside and air/gas environments are subject to the

aging effects of change in material properties, cracking, and loss of material. -

* Copper alloy components exposed to a dried gas or inside environment experience no

aging effects.

* Copper alloy components exposed to wetted air/gas or outside environments are subject

to the aging effect of loss of materials. -

* -Aluminum fins exposed to a wetted air/gas environment are subject to loss of material

:and fouling aging effects. - . -

* Galvanized steel and stainless steel components exposed to an inside or air/gas

environment experience no aging effects.-

* Carbon steel components exposed to an air/gas environment are subject to the loss of

material aging effect. - - -

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The staff reviewed the information in Section 2.3.3.9, Table 2.3.3.9, Section 3.3.2.1.9, and

Table 3.3.2-9 of the LRA. During its review, the staff determined that it needed additional

information.

The staff organized the RAls into general RAls and system-specific RAls. General RAls

applicable to this system include RAls 3.3-6, 3.3-7, and 3.3-16.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-6, 3.3-7, and 3.3-16. By letter dated April 7,

2004, the applicant responded to these RAls. Section 3.3.2.3.0 of this SER describes these

RAls, the applicant's responses, and the staff's evaluation of the responses.

By the same letter dated March 8, 2004, the staff asked the applicant to provide additional

information on the issues described in the system-specific RAI 3.3.2.1.9-1. By letter dated

April 7, 2004, the applicant responded to this RAI. The following describes RAI 3.3.2.1.9-1, the

responses to this RAI, and the staff's evaluation of the responses.

Aging Effect of Aluminum Fins in Heat Exchangers Due to Galvanic Corrosion (RAI

3.3.2.1.9-1). Loss of material due to galvanic corrosion may be a susceptible aging effect on

the contact area of aluminum fins and copper tubes of the heat exchangers that are exposed to

a wetted air/gas environment. However, it was not clear in the LRA if the One-Time Inspection

Program includes galvanic corrosion. The staff asked the applicant to clarify if the One-Time

Inspection Program will manage the galvanic corrosion on the contact area of aluminum fins

and copper coils.

In response, by letter dated April 7, 2004, the applicant stated that per LRA Table 3.3.2-9, loss

of material is an AERM for the aluminum fins, which are in contact with the copper direct

expansion cooling tubes inside the control room A/C cooling coils (heat exchangers). Because

of the lower galvanic potential of the aluminum fins relative to the copper tubing, the loss of

material for the aluminum fins due to galvanic corrosion in the wetted air/gas environment is an

AERM in the vicinity where the two materials are in contact. Therefore, the applicant stated that

the aluminum fins are conservatively included within the scope of the One-Time Inspection

Program for loss of material due to galvanic corrosion. However, the applicant claimed that

galvanic corrosion is not expected to be significant. Cooling coils constructed of copper tubes

and aluminum fins have proved reliable in HVAC applications. The applicant also stated that it

will use the One-Time Inspection Program to verify that significant loss of material is not

occurring, including that from galvanic corrosion.

The staff reviewed the applicant's response to RAI 3.3.2.1.9-1 and found the response to be

reasonable and acceptable because the applicant clarified that the aluminum fins are

conservatively included within the scope of the One-Time Inspection Program for the loss of

material due to galvanic corrosion, and that cooling coils constructed of copper tubes and

aluminum fins have proved reliable in HVAC applications.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects of the control room area

ventilation system component types given above that are not addressed by the GALL Report

are consistent with industry experience for these material-environment combinations. The staff

did not identify any omitted aging effects. Therefore, the staff finds that the applicant has

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identified the appropriate aging effects for the materials and environments associated with the'

above components in the control room area ventilationsystem.

Aging Management Programs :

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determ ine if they areappropriate for rmanaging the identified

aging effects. The staff also determined that the FSAR Supplement contains an adequate

description of the program.

Table 3.3.2-9 of the LRA identifies the following AMPs for managing the aging effectsdescribed

above for the control room area ventilation' system. ' - ' . ;

* External Surfaces Monitoring Program (Appendix B.5.3)

* One-Time Inspection Program (Appendix B.5.5)

The applicant credited the External Surfaces Monitoring Program with managing the aging

effect of loss of material on copper alloy components exposed to an inside environment. The

staff reviewed the material, environment, and aging effects on these components, and the

adequacy of this AMP for'maniaging the identified aging effects. ' The staff finds this AMP'

adequate because it uses periodic inspections'of the most su'sceptible components and

locations to establish a baseline, trends the degradations, and takes corrective actions to'-

prevent further degradations if such actions are warranted. The applicant has expanded the

scope of this AMP to include the flexible connectors and floor drain plug elastomer components,

as discussed in the applicant's response to RAI 3.3-6 in Section 3.3.2.3.0 of this SER. The

staff notes that, in' the original description of the AMP B.5.3 in Section B.5.3.6 of the- LRA, the*

applicant stated that it would also inspect accessible in-scope polymers or elastomer6 for'agerelated degradation. '. - .

The One-Time Inspection Program manages several different AERMs. The staff reviewed the

utilization of the One-Time Program 'nspection for these different combinations of materials,

environments, and AERMs for the components in'the control room area ventilation system and

finds this AMP to be adequate for managing the idenitified agirng eff6cts because'these aging

effects are expected to occur at a relatively slow rate; - -

The staff's detailed review of these AMPs appears in Section's 3.0;3.3.2 and 3.0.3.1 of this:

SER, respectively.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified appropriate AMPs for managing the aging~ effects of the controliroom

area ventilation system component types that are. not addressed by the GALL' Report.' In

addition, the staff finds' the program descriptions iri the FSAR Supplement acceptable.

Conclusion '-' -- '

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited with managing the aging effects, for the control room area

ventilation 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

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operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR' Supplement program summaries and con'cludes

that the FSAR 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 Auxiliary and Radwaste Area Ventilation System

Summary of Technical Information in the Application

In Section 3.3.2.1.10 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs that manage the aging effects related

to the auxiliary and radwaste area ventilation system:

* One-Time Inspection Program

* External Surfaces Monitoring Program

* Service Water Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-10 of the LRA, the applicant summarized the AMRs for the auxiliary and

radwaste area ventilation components and identified which AMRs it considered to be consistent

with the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the auxiliary and radwaste area ventilation' system, components

relating to those combinations of components, materials, envirotnments, and AERMs and found

them to be consistent with the GALL Report. These combinations use notes A through' E in

LRA Table 3.3.2-10. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the auxiliary and radwaste' area ventilation system relating to

those combinations of components, materials, environments,'and AERMs that the GALL Report

does not address. These combinations use notes Fthrough J in LRA Table 3.3.2-10. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs with managing the AERMs. The staff also reviewed the applicable FSAR Supplements'

for the AMPs to ensure that the program descriptions are adequate.

Aging Effects

Table 2.3.3.10 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components that do not rely on the GALL Report for an

AMR include closure bolting, compressible joints and seals, ducts and fittings, equipment

frames and housing, cooling units, fire dampeners (frames and housing only), flexible

connectors, flow orifice/element, piping, Pitot tubes, and valve bodies.

For these component types, the applicant identified the following materials, environments, and,

AERMs:

* Elastomer components exposed to inside and air/gas environments are subject to the

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aging effects of change hi material properties cracking; arid loss of material.

* Copper alloy and carbon steel components exposed to an air/gas or inside environment

experience no aging effects. : -

* Copper alloy components exposed to air/gasrand inside environments are subject to the

aging effect of loss of materials. -

* Copper alloy fins exposed to'a'wetted air/gas environment are subject to the loss of

material and fouling aging effects.

* 'Stainless steel components exposed to an inside or air/gas environment experience no

aging effects.

* Galvanized steel components exposed to an inside environment are subject to the aging

effect of loss of materials.

* ' Carbon steel components exposed to an air/gas environment are subject to the loss of

material aging effect.

The staff reviewed the information in Section 2.3.3.10, Table 2.3.3.10,-Section 3.3.2.1.10, and

Table 3.3.2-10 of the LRA. During its review, the staff determined that it needed additional -

information.

The staff organized its RAls into general RAls and system-specific RAls: General RAls -7

applicable to this system include RAls 3.3-6; 3.3-7, 3.3-8, 3.3-12, and 3.3-16. There are no

relevant system-specific RAls. L

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-6, 3.3-7, 3.3-8, 3.3-12, and 3.3-16. By letter

dated April 7, 2004, the applicant responded to these RAls. Section 3.3.2.3.0 of this SER

describes these RAls, the applicant's responses, and the staff's evaluation of the responses.

On the-basis of its review of the LRA and the additional information included in the applicant's - response to the above RAls, the staff finds-that the'aging effects of the auxiliary and radwaste

area ventilation system component types not addressed by the GALL Report are consistent with

industry experience for these material-environment combinations. 'The staff did not identify any

omitted aging effects. Therefore, the staff finds that the applicant has identified the appropriate

aging effects for the materials and environments associated with the above components in the

auxiliary and radwaste-area ventilation systen.s '- - -; . ,- S-.

Aging Management Programs'-

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-10 of the LRA and the applicant's response to RAI 3.3-6 identify the following AMPs

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for managing the aging effects described above for the auxiliary and radwaste area ventilation

system:

* Borated Water Leakage Assessment and Evaluation Program (Appendix B.3.5)

* Service Water Program (Appendix 6.4.4)

* One-Time Inspection Program (Appendix B.5.5)

* External Surfaces Monitoring Program (Appendix B.5.3)

The applicant credited the Borated Water Leakage Assessment and Evaluation Program with

managing the aging effects of loss of material due to boric acid corrosion on carbon steel and

galvanized steel components exposed to an inside environment. The staff reviewed the

material, environment, and aging effects for these components and this AMP and finds that this

AMP is adequate for managing the identified aging effects because it is consistent with the

Boric Acid Corrosion Program in the GALL Report. The effectiveness of the latter is consistent

with industry experience.

The applicant credited the Service Water Program with managing the aging effect of loss of

heat transfer function resulting from fouling on the fins of the cooling units. The staff reviewed

the material, environment, and aging effects for these components and this AMP and finds that

this AMP is adequate for managing the identified aging effects because it implements NRC GL

89-13 and uses the combinations of periodic flushing and regular heat exchanger cleaning to

prevent and mitigate fouling, volumetric examination to detect pipe wall thinning, and visual

inspections for fouling and loss of material.

The applicant uses the One-Time Inspection Program for managing several different AERMs.

The staff reviewed the utilization of the One-Time Inspection Program for these different

combinations of materials, environments, and AERMs for the components in the auxiliary and

radwaste area ventilation system and finds that this AMP is adequate for managing the

identified aging effects because these aging effects are expected to occur at a relatively slow

rate.

The applicant credited the External Surfaces Monitoring Program with managing the aging

effect of loss of material on copper alloy components exposed to an inside environment. The

staff reviewed the material; environment, and aging effects for these components and the

adequacy of this AMP for managing the identified aging effect. The staff finds this AMP

adequate because it uses periodic inspections of the most susceptible components and

locations to establish a baseline, trends the degradations, and takes corrective actions to

prevent further degradations if such actions are warranted. The applicant has expanded the

scope of this AMP to include the flexible connectors and floor drain plug elastomer components,

as discussed in the applicant's response to RAI 3.3-6 in Section 3.3.2.3.0 of this SER. The

staff notes that, in the original description of the AMP B.5.3 in Section B.5.3.6 of the LRA, the

applicant stated that it will also inspect accessible in-scope polymers or elastomers for agerelated degradation.

The staff's detailed review of these AMPs appears in Sections 3.0.3.1.1, 3.0.3.2.5, 3.0.3.1, and

3.0.3.3.2 of this SER, respectively.

On the basis of its review of the information provided in the LRA, the staff finds the applicant

has identified appropriate AMPs for managing the aging effects of the auxiliary and radwaste

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I
area ventilation system component types not addressed by the GALL Report. In addition, the

staff finds the program descriptions in the FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited with managing the aging effects, for the auxiliary and

radwaste area ventilation system components not addressed by the GALL Report, so that the

intended functions will be maintained conisistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).-

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.11 Primary Containment Ventilation System

Summary of Technical Information in the Ap6lication

In Section 3.3.2.1.11 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the followinrg`programs that manage the aging effects related

to the primary containment ventilation system:

* ' One-Time Inspection Program ;

* External Surfaces Monitoring Program

* Service Water Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-11 of the LRA, the applicant summarized the AMRs for the primary containment

ventilation system components and identified'which AMRs it considered to be consistent with

the GALL Report. '

Staff Evaluation

The staff reviewed the AMRs of the primary containment ventilation' system components

relating to those combinations of components, materials, environments, and AERMs and found

them to be consistent with the GALL Report. These combinations use notes A through E in

LRA Table 3.3.2-11. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of th6 primaiy cdritainment ventilation system relating to those

combinations of components, materials,' einvirornm-ents, and AERMs not addressed in the GALL

Report. These combinations use notes F through J in LRA Table 3.3.2-11. The staff

determined that the applicant has id6rtified all appli6able AERMs and has credited appropriate

AMPs with managing the'AERMs. The staff also reviewed the applicable FSAR Supplements

for the AMPs to ensure that the program sdmmaries adequately describe the AMPs.

Aging Effects

Table 2.3.3.11 of the LRA lists individual system components within the scope of license

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q

renewal and subject to an AMR. The components that do not rely on the GALL Report for an

AMR include closure bolting, compressible joints and seals, ducts and fittings, equipment

frames and housing, cooling coil (fins only), fire dampeners (frames and housing only), flexible

connectors, flow orifice/element, piping, Pitot tubes, and valve bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Elastomer components exposed to inside and air/gas environments are subject to the

aging effects change in material properties, cracking, and loss of material.

* Copper alloy and carbon steel components exposed to air/gas or inside environments

experience no aging effects.

* Copper alloy components exposed to air/gas or inside environments experience no

aging effects.

* Copper alloy fins exposed to a wetted air/gas environment are subject to loss of material

and fouling aging effects.

* Stainless steel components exposed to inside or air/gas environments experience no

aging effects.

* Galvanized steel components exposed to an inside environment are subject to the aging

effect of loss of materials.

* Carbon steel components exposed to an air/gas environment are subject to the loss of

material aging effect.

The staff reviewed the information in Section 2.3.3.11, Table 2.3.3.11, Section 3.3.2.1.11, and

Table 3.3.2-11 in the LRA. During its review, the staff determined that it needed additional

information.

The staff organized the RAls into general RAls and system-specific RAls. General RAls

applicable to this system include RAls 3.3-6, 3.3-7, 3.3-8, 3.3-12, 3.3-14, and 3.3-16. There are

no relevant system-specific RAls.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-6, 3.3-7, 3.3-8, 3.3-12, 3.3-14, and 3.3-16. By

letter dated April 7, 2004, the applicant responded to these RAls. Section 3.3.2.3.0 of this SER

describes these RAls, the applicant's responses and the staff's evaluation.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds the aging effects of the above primary containment

ventilation system component types that are not addressed by the GALL Report to be

consistent with industry experience for these material-environment combinations. 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 primary containment ventilation system.

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!l
Aging Management Programs

After evaluating the applicant's identification of aging 'effects for each of the above components,

the staff reviewed the AMPs'to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program. - - -- 

Table 3.3.2-11 of the LRA and the applicant's response to RAI 3.3-6 identify the following AMPs

for mamnaginig the aging'effects described above for th'e'primary containment ventilation system:

* Service Water Program (Appendix B.4.4)'

* One-Time Inspection Program (Appendix B.5.5)

* External Surfaces Monitoring Program (Appendix B.5.3) - -

The applicant credited the Service Water Program with managing the aging effect of loss of

heat transfer function resulting from fouling on the fins of the cooling units. The staff reviewed

the material, 'environmentfand aging effects'for these'components and this AMP and finds that

this AMP is adequate for managing the identified'aging effects because it implements NRC GL

89-13 and uses the combinations of periodic flushing and regular heat exchanger cleaning to .

prevent and mitigate fouling, volumetric examination to detect pipe wall thinning, and visual

inspections for fouling and loss 6f material.--:

The applicant uses the One-Time Inspection Program for managing several different AERMs.

The staff reviewed the utilization of the One-Time Inspection Program for these different

combinations of materials, environments, and AERMs for the components in the primary - --

containment ventilation system and finds that this AMP is adequate for managing the identified

aging 'effect because'these aging effects are expected to occur at a relatively slow rate;

The applicant credited the External Surfaces'Monitoring Program with managing the aging

effect of loss of material on copper alloy components exposed to an inside environment. The

staff reviewed the material, environment, and aging effects for these components and the

adequacy of this-AMP for managing the identified aging effect. The staff finds this AMP

adequate because it uses periodic inspections of the most susceptible components and -

locations to establish a baseline, trends the degradations, and takes corrective actions to.

prevent further degradations if such actions are warranted. The applicant has expanded the

scopeof this AMP to include the flexible connectors and floor drain plug elastomer components,

as discussed in the applicant's response to RAI 3.3-6 in Section 3.3.2.3.0 of this SER. The

staff notes that, in the original description of AMP B.5.3 in Section B.5.3.6 of the LRA, the

applicant stated that it will also inspect accessible in-scope polymers or elastomers for agerelated degradation.

The staff's detailed review of these AMPs appears in Sections 3.0.3.2.5, 3.0.3.1, and 3.0.3.3.2-

of this SER, respectively. ' . . - - :

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the primary containment ventilation system component

types that are not addressed by the GALL Report. In addition, the staff finds the program

descriptions in the FSAR Supplement acceptable' -

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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 primary.:

containment ventilation system components that are not addressed by the GALL Report, so that

the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.12 Yard Structures Ventilation System

Summary of Technical Information in the Application

In Section 3.3.2.1'.12 of the LRA, the applicant identified the materials, environments, and. -

AERMs. The applicant identified the External Surfaces Monitoring Program to manage the

aging effects related to the yard structures ventilation system.

In Table 3.3.2-12 of the LRA, the applicant summarized the AMRs for the yard structures

ventilation system components and identified which AMRs it considered to be consistent with

the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the yard structures ventilation system components relating to

those combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-12. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the yard structures ventilation system relating to those

combinations of components, materials, environments, and AERMs that are not addressed in

the GALL Report. These combinations use notes F through J in LRA Table 3.3.2-12. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs with managing the AERMs. The staff also reviewed the applicable FSAR Supplements

for the AMPs to ensure that the program descriptions are adequate.

Aging Effects

Table 2.3.3.12 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components that do not rely on the GALL Report for an

AMR include ducts and fittings and equipment frames and housing.

For these component types, the applicant noted that galvanized steel components exposed to

an air/gas and inside environment do not experience any aging effects.

The staff reviewed the information in Section 2.3.3.12, Table 2.3.3.12, Section 3.3.2.1.12, and

Table 3.3.2-12 of the LRA. During its review, the staff determined that it needed additional

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information.

The staff organized its RAls into general RAls and system-specific RAls.':General RAls '

applicable to this system include RAls 3.3-7 and 3.3-9. There are no relevant system-specific

RAls. - -

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information 'on the issuesdescribed in RAls 3.3-7 and 3.3-9. By letter dated April 7, 2004, the

applicant responded to these RAls; -Section 3.3.2.3.0 of this SER describes these RAls, the

applicant's responses, and the staff's evaluation of the responses.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects of the'yard structures

ventilation system'component types not addressed by the GALL Report are'consistent with

industry experience'for these material-environment combinations. The staff did not identify any

iomitted 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

yard'structures ventilation system. '' - -

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects.' 'The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-12 of the LRA identifies no AMP for managing the aging effects described abovefor the yard structures ventilation system.

On the basis of its review of the information provided in the LRA, the staff finds that no AMP is

needed for managing the aging effects of the yard structures ventilation system component

types that are not addressed by the GALL Report.

Conclusion - ' ..

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and no AMP is needed for managing the aging effects for the yard structures

ventilation system components that are not addressed by the GALL Report, so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as 'required by 10 CFR 51.21 (a)(3). * f- -

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by'10 CFR'54.21(d). '

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3.3.2.3.13 Fire Protection System

Summary of Technical Information in the Application

Section 2.3.3.13 of this SER describes the fire protection system. Table 2.3.3.13 of the LRA

identifies the passive, long-lived components of this system that are subject to an AMR. A

summary of the components, aging effects, and AMPs appears in LRA Tables 3.3.1 and.

3.3.2-13. Table 3.3.1 includes references to the RCP oil collection system and fire barriers,

although other sections of the LRA address these components.

Aging Effects

Table 2.3.3.13 of the LRA lists the fire protection components that are within the scope of

license renewal and subject to an AMR. -These components include bolting, fire hydrants,,.

flexible connections, flow orifices, fusible links and sprinkler head bulbs, hose station nozzles

and connections,. water system piping and valves, gas system piping and valves, fuel oil system

piping and valves, pump casings, sight glasses, spray shields, sprinkler heads, strainers, tank

protective cover, water system tanks, gas system tanks, fuel oil system tanks, and thermal

insulation.

In Section 3.3.2.1.13 and LRA Table 3.3.2-13, the applicant identified the materials,

environments, and AERMs. The materials identified include carbon steel, alloy steel, stainless

steel, aluminum, cast iron, galvanized steel, lead alloys, and copper alloys. In addition, the

applicant addressed a commodity class called "fibers, foams, and ceramics" in Table 3.3.2-13

as applying to thermal insulation on the C02 tank. Table 3.3.2-13 identifies "fusible links and

sprinkler heads bulbs" as a component type using the materials of copper alloy; fiber, foams

and ceramics; and lead alloys.

The applicant identified the environments to which these materials could be exposed as air and

gas (wetted, ambient and dried), raw water (well water), and fuel oil. Section 3.3.2.1.13 of the

LRA further identified environments as including inside (with the potential for borated water

leakage), outside, and buried.

The applicant identified cracking, loss of material, fouling, and changes in material properties as

the aging effects associated with the fire protection system components in LRA Section

3.3.2.1.13.

Aging Management ProgramsThe LRA identifies the following programs that manage the aging effects related to the fire

protection system:

* Fire Protection Program (Appendix B.4.5)

* Fuel Oil Chemistry Control Program (Appendix B.4.2)

* One-Time Inspection Program (Appendix B.5.5)

* External Surfaces Monitoring Program (Appendix B.5.3)

* Buried Piping and Tank Inspection Program (Appendix B.5.4)

* Borated Water Leakage Assessment and Evaluation Program (Appendix B.3.5)

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The sections of LRA Appendix B listed in parentheses above describe these AMPs. The

applicant indicated that these AMPs will adequately manag e effects of aging associated

with the components of the'fire protection'system during the period of extended operation. V , , .. , ,* 1 ' -^-'''v''''

Staff Evaluation

The staff reviewed the LRA to determine whether the applicant had demonstrated that it would

adequately manage the effects of aging for the fire protection system during the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff reviewed Section 3.3.2.1.13

and Tables 3.3.1 and 3.3.2-13 of the LRA f6r.bompleteness and consistency with the GALL --

Report and industry experience.

Table 3.3.1 of the LRA includes the RCP oil collection system under Item 3.3.1-6 and

references Section 3.3.2.2.6. Item 3.3.1-30 addresses fire barriers and references Section 3.5.

During its review, the staff requested'additional information to complete its evaluation of the fire

protection portions of the LRA. By letter dated March 23, 2004, the staff issued RAI 2.0-2H

(D-RAI 3.3.2.13-1) requesting that the applicant describe the components identified as "Spray

shields" in Tables 2.3.3.13 and 3.3.2-13 and state where these components are used. In its

response dated April 7, 2004, the applicant stated that it uses the spray shields to limit the

sprinkler flow to specific targets in the event of a suppression system actuation. These devices

are attached to the sprinkler piping and are depicted on the sprinkler system boundary.

drawings. The response indicated that these' shields are constructed of sheet metal, and LRA

Table 3.3.2-13 identifies the material as either aluminum or galvanized steel. Based on this

information,'the staff finds the AMR for these components adequately addressed.

Table 3.3.2-13, under water system piping, identifies'cement-lined cast iron piping as not

requiring aging management. The applicant based this conclusion on testing it performed on

representative samples of the buried piping in 2003. Section 3.3.2.1.13 of the LRA describes

the results of this testing and concludes there are no indications of aging effects that would

require management for the period of extended operation. The staff concurs that these tests

are a valid approach to evaluate the soil conditions that could affect the external surfaces of the

piping. Additionally, the water quality and the cement lining of the pipe obviate the need for

aging management. -

On the basis of its review of the LRA, the staff finds that the aging effects resulting from

exposure of the fire protection system components to the environments described in LRA Table

3.3.2-13 are consistent with the GALL Report and with industry experience for these materialenvironment combinations. Therefore, the staff finds that the applicant identified the applicable

aging effects and associated AMPs, and they are appropriate for the combination of materials

and environments listed.

Aging Management Programs

The applicant credited the following AMPs with managing the aging effects in the fire protection

system:

* Fire Protection'Program' (Appendix B.4.5) '

* Fuel Oil Chemistry Control Program (Appendix B.4.2)

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I

* One-Time Inspection Program (Appendix B.5.5)

* External Surfaces Monitoring Program (Appendix B.5.3)

* Buried Piping and Tank Inspection Program (Appendix B.5.4)

* Borated Water Leakage Assessment and Evaluation Program (Appendix B.3.5)

These AMPs are credited with managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and found them acceptable for managing the aging effects identified for this

system. The evaluation of these AMPs appears in Section 3.0.3 of this SER, as indicated

above. Table 3.0.3-1 of this SER presents the AMPs credited by the applicant and described in

Appendix B to the LRA.

On the basis of its review of the information provided by the applicant, the staff concludes that

the applicant has credited the appropriate AMPs with managing the aging effects from the

materials and environments associated with the fire protection system and that the AMPs

identified above will effectively manage these aging effects.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects and AMPs credited with managing the aging effects for the components of the fire

protection system, so that the intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.14 Diesel Fuel Oil System

Summary of Technical Information in the Application

In Section 3.3.2.1.14 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 diesel fuel oil system:

* Fuel Oil Chemistry Control Program

* One-Time Inspection Program

* External Surfaces Monitoring Program

* Buried Piping and Tank Inspection Program

In Table 3.3.2-14 of the LRA, the applicant summarized the AMRs for the diesel fuel oil system

components and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the diesel fuel oil system components relating to those

combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

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3.3.2-14. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the diesel fuel oil system relating to those combinations of

components, materials; environments, and AERMs that are not addressed iri the'GALL Report.

These combinations use notes F through J in LRA Table 3.3.2-14; The staff determined that''

the applicant has identified all applicable AERMs and has credited appropriate AMPs for

managing the AERMs. The staff also reviewed the applicable FSAR Supplements for the

AMPs to ensure that the program descriptions are adequate.

Aging Effects -

Table 2.3.3.14 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 piping, guard pipe, pump casings, strainers (element), strainers'(shell),'tanks, - valve bodies; and vent screens. -.

For these component types, the applicant identified the following materials, environments, and

AERMs: .;...) e

:Carbon steel, alloy steel, copper and Ni-Cu alloys, cast iron,-'nd 'stainless steel

components exposed to a fuel oil environment are subject to the aging effect of loss of

material. - -. .

* Carbon steel and alloy steel components exposed to an inside environment are subject - -to the aging effect of loss of material. .

* Copper and Ni-Cu alloys, cast iron, and stainless steel components in an inside

environment experience no applicable aging effects.

* Stainless steel components in a protective trench experience loss of material.

* 'Carbon steel and alloy steel components in air/gas environments as well as carbon steel

components in an outside environment are subject toIth6 loss of material aging effect.'

* -Carbon steel components in an embedded environment havie no applicable aging

effects. -

The staff reviewed the information in Section 2.3.3.14, Table 2.3.3.14, Section 3.3.2.1.14, and

Table'3.3.2-14 of the LRA. -During its review, the staff determined that it needed additional

information. - . ;" ,

The staff organized its RAls into general RAls and system-specific RAls. The general RAI

applicable to this system is RAI 3.3-9.-.;

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAI 3.3-9. By letter dated April 7,'2004,' the'applicant

responded to this RAI. Section 3.3.2.3.0 of this SER describes this RAI, the applicant's

responses, and the staff's evaluation' of the responses.

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By the same letter dated March 8, 2004, the staff asked the'applicant to provide additional

information on the issues described in system-specific RAIs 3.3.2.1.14-1 and 3.3.2.1.14-2. By

letter dated April 7, 2004,' the applicantresponded. Descriptions of RAts 3.3.2.1.14-1 and

3.3.2.1.14-2, the responses to these RAts, and the staff's evaluation of the responses appear

below.

"Inside-in Protective Trench" ' Regular"Inside" Environments (RAI 3.3.2.1.14-1). In LRA

Table 3.3.2-14 for the diesel fuel oil system, the applicant identified loss of material as the aging

effect for carbon steel, alloy steel, and stainless steel pipes exposed to an inside (protective

trench) environment. The LRA does not define the protective trench environment. The staff

asked the applicant to describe this environment and discuss the differences between it and the

regular inside environment (in particular, as r~elated to aging mechanisms and aging effects).

For managing this aging effe-t, the LRA identifies the' External Surface Monitoring Program for

carbon steel and alloy steel piping, whereas it uses the One-Time'Inspection Program for

stainless steel piping. The staff asked the applicant to explain the basis for using different

AMPs.

In response, by letter dated April 7, 2004, the applicant stated that the piping trenches in the.

EDG bays are located in the inside environment associated with the diesel generator building.

The trenches are recessed inihe floor and therefore are a low point that could collect any spills

or leaks occurring in the area. Because these piping trenches are covered, the applicant did

not perform a visual inspection of the conditions in the trenches before it submitted the LRA.

While the piping that runs in these trenches is supported off the floor by spacers at regular

intervals, SNC felt it prudent to examine the piping inrthe trenches to confirm the conditions in

the trenches (i.e., to check for evidence of spills or immersion) and any impact on the installed

piping. Therefore, the applicant created a distinct environment of "inside-in protective trench"

to ensure that the specified AMPs would inspect the condition of the external surfaces of the

piping in the trenches.

The applicant also'stated in the LRA for mechanical systems that it utilizes the Exterior.

Surfaces Monitoring Program to inspect carbon and low-alloy steel external surfaces in an

inside environment and, therefore, it is appropriate and consistent for managing aging of the

external surfaces of the carborn-and low-alloy piping in the trenches. However, stainless steel

external surfaces in an inside environment do not have an AERM. Stainless steel is inherently

corrosion resistant. Therefore, the applicant concluded that the One-Time Inspection Program

is appropriate to perform an inspection to confirm that detrimental aging of stainless steel piping

in the trenches is not occurring.

The staff reviewed the applicant's response to RAI 3.3.2.1.14-1 and found the response to be

reasonable and acceptable because the applicant clarified that it had created a distinct

environment of 'inside-in protective trench" to ensure that the AMPs specified would inspect

the condition of the external surfaces of the piping in the trenches, and that the One-Time

Inspection Program is appropriate to perform an inspection to confirm that detrimental aging of

stainless steel piping in the trenches is not occurring. The use of the One-Time Inspection

Program is acceptable because stainless steel is inherently corrosion resistant.

Justification for Use of One-Time Inspection for Aping Manaaement of Carbon Steel

Components in an Outside Environment (RAI 3.3.2.1.14-2). For the carbon steel vent cap and

screen in an outside environment, the LRA credits the One-Time Inspection Program with

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managing the loss of material. 7The One-Time Inspection Program is intended for components

where no significant aging' isexpected.' Since general corrosion is expected to occur in carbon

steel in an outside'environment, periodic inspection may be more appropriate than a one-time

inspection. The staff asked the applicant to provide additional justification for use of.a one-time

inspection in' lieu of periodic inspection for this'component.

In response, by letter dated April 7, 2004, the applicant stated that it agrees that periodic

inspection isr -ore appropriate for managing loss of material in carbon steel components

exposed to an outside'environment. The applicant also agreed that the LRA Table 3.3.2-14 line

item for the vent cap and screen is in error. - -

The applicant stated that the carbon steel vent screen for the diesel generator fuel oil storage

tanks has an outside exterior environment. The External Surfaces Monitoring Program will

provide periodic inspection of the external surfaces in an outside environment. The interior

environment of the vent screen is predominately the same environment as the vapor space of.-,

the fuel oil storage tanks. Inspection has shown the vapor space of the fuel oil storage tanks to

be free of detrimental aging effects. Therefore, the applicant concluded that a one-time

inspection in lieu of periodic inspection is appropriate for the interior of the vent screen

component exposed to an' air/gas environment. - -

Based on these considerations, the applicant revised the vent screen line item in LRA Table

3.3.2-14.

The staff reviewed the applicant's response to RAI 3.3.2.1.14-2 and found the response to be

reasonable and acceptable because the applicant agreed that periodic inspection is more

appropriate for managing loss of material in carbon steel components exposed to an outside

environment and has revised the vent screen line item in LRA Table 3.3.2-14, consistent with

the above agreement.

On the basis of its'review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds'that the aging effects of the diesel fuel oil system

component types given above that are not addressed by the GALL Report are consistent with

industry experience for these material-environment combinations. 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

diesel fuel oil system. -

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-14 of the LRA identifies the following AMPs for managing the aging effects

described above for the diesel fuel oil system:

* Fuel Oil Chemistry Control Program (Appendix B.4.2)

* One-Time Inspection Program (Appendix B.5.5)

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The applicant uses the Fuel Oil Chemistry Control Program for managing several different

AERMs. 'The staff reviewed the utilization of the Fuel Oil Chemistry Control Program in these

different combination's of materials, environments, and AERMs for the components in the diesel

fuel oil system. The staff finds that this AMP is adequate for managing the identified aging

effects for two reasons. First, this AMP is consistent with the 10 attributes of the AMPs

described in GALL,'Section XI.M30, with the exception that the specific ASTM standards that

FNP uses as guidelines for sampling and sample analysis are governed by the plant TSs and

differ from those cited in the GALL Report. However, no significant difference exists in the

ability of the program to manage aging effects. Second, the effectiveness of these GALL AMPs

is consistent with industry experience.

The applicant uses the One-Time Inspection Program for managing several different AERMs.

The staff reviewed the utilization of the One-Time Inspection Program for the different

combinations of materials, environments, and AERMs for the components in the diesel fuel oil

system and finds that this AMP is adequate for managing the identified aging effects because

they are expected to occur at a relatively slow rate.

The staff's detailed review of these AMPs appears in Sections 3.0.3.2.3 and 3.0.3.1 of this

SER, respectively.

On the basis of its review of the information provided in the LRA, the staff finds that the

applicant has identified appropriate AMPs for managing the aging effects of the diesel fuel oil

system component types that are not addressed by the GALL Report. In addition, the staff

finds the program descriptions in the FSAR 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 diesel fuel oil

system components that are not addressed by the GALL Report, so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21(a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited with managing aging in

these components, as required by 10 CFR 54.21 (d).

3.3.2.3.15 Emergency Diesel Generator System

Summary of Technical Information in the ADplication

In Section 3.3.2.1.15 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 EDG system:

* Water Chemistry Control Program

* One-Time Inspection Program

* Service Water Program

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* External Surfaces Moniibring Program'

In Table 3.3.2-15 of the LRA; the applicant summarized the AMRs for the EDG system

components'and identified which AMRs it considered to be consistent with the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the EDG system components relating to those combinations of

components, materials, environments, and AERMs and found them to be consistent with the

GALL Report. These combinations use notes A through E in LRA Table 3.3.2-15. Section

3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the EDG system relating to those combinations of components,

materials, environments, and AERMs that are riot addressed in the GALL Report. These

combinations use notes' F through J in LRA Table 3.3.2-15. The staff determined that the

applicant has identified all applicable AERMs and has credited appropriate AMPs for managing

these effects. The staff also reviewed the applicable FSAR Supplements for the AMPs to

ensure that they adequately describe the AMPs. .

Aging Effects

Table 2.3.3.15 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 air accumulators, ducts and fittings, electric heaters, equipment frames and

housings, filters (casing),'-heat exchanger (channel head), heat exchanger (shell), heat - :

exchanger (tubesheet), heat exchanger (tubes);piping, pump casings, strainers (element),

strainers (shell), tanks,-and valve bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Copper alloy and stainless steel compofients in an air/gas (wetted) environment are - subject'to cracking and loss of material::

* ' Copper alloy components in raw water closed-cooling water environments have the

aging effects of loss of material, fouling, and leaching, while these components in

closed-cooling water environments are subject to the loss of material.

*' Carbon steel, copper alloys, cast ironand stainless steel components exposed to dried

gas'or 'lube oil environments have no applicable aging effects. -

* 'Both stainless steel components in an outside environment and copper alloy

components subjected to an air/gas'environment do not experience any aging effects.

The staff reviewed the'information in Section 2.3.3.15, Table 2.3.3.15, Section 3.3.2.1.15, and

Table 3.3.2-15 of the LRA. During its review, the staff determined that it needed additional

information.

The staff organized its RAls into general RAls and system-specific RAls. General RAls

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i

applicable to this system include RAls 3.3-9, 3.3-11, 3:3-13, and 3.3-14.

By letter dated March 8, 2004, the staff asked the applicant to provide additional information on

the issues described in RAls 3.3-9, 3.3-11, 3.3-13, and 3.3-14. By letter dated April 7, 2004,

the applicant responded to these RAls. Section 3.3.2.3.0 of this SER describes these RAls, the

applicant's responses and the staff's evaluation of the responses.

By the same letter dated March 8, 2004, the staff asked the applicant to provide additional

information on the issues described in system-specific RAls 3.3.2.1.15-1 and 3.3.2.1.15-2. By

letter dated April 7, 2004, the applicant responded to these RAls. The following describes RAls

3.3.2.1.15-1 and 3.3.2.1.15-2, the responses to these RAls, and the staff's evaluation of the

responses.

Water Chemistry Control Program Credited for Managing the Aging Effect for Piping Without

One-Time Inspection (RAI 3.3.2.1.15-1). The LRA identifies copper alloy in a closed-cooling

water environment as subject to the loss of material. For the heat exchanger components

(Table 3.3.2-15, p. 3.3-119), the LRA credits the One-Time Inspection Program in conjunction

with the Water Chemistry Control Program for aging management. However, for piping (Table

3.3.2-15, p.3.3-122), the LRA only credits the Water Chemistry Control Program. The staff

asked the applicant to discuss the different aging management of apparently similar materials,

environments, and AERMs.

By letter dated April 7, 2004, the applicant responded by stating that it should have listed the

One-Time Inspection Program in conjunction with the water chemistry controls for the EDG

cooling water system copper alloy piping and valve bodies in the closed-cooling water

environment in Table 3.3.2-15. The applicant agreed that it inadvertently omitted this AMP.

The applicant further stated that its aging management results utilize the One-Time Inspection

Program to confirm the effectiveness of the Water Chemistry Control Program to control the

loss of material for copper alloy components in the CCCW environment.

The staff finds the applicant's response to be reasonable and acceptable because the applicant

agreed that it should have listed the One-Time Inspection Program in conjunction with the water

chemistry controls, and because the applicant confirmed that its aging management results

utilize the One-Time Inspection Program to confirm the effectiveness of the Water Chemistry

Control Program to control the loss of material for copper alloy components in the CCCW

environment.

Stress-Corrosion Cracking as an Applicable Aging Effect for Stainless Steel Components in the

Intake/Exhaust System in the Emeraencv Diesel Generator System (RAI 3.3.2.1.15-2). Table.

3.3.2-15 of the LRA identifies loss of material as the applicable aging effect for most copper

alloy or stainless steel components of the EDG system that are exposed to an air/gas (wetted)

environment. The LRA credits the One-Time Inspection Program for aging management.

However, for ducts and fittings in the intake/exhaust system, and for the pipes and valve bodies

in the air start system, the LRA also identifies cracking as an applicable aging effect and credits

the One-Time Inspection Program for aging management. The staff asked the applicant to

explain the difference in aging effects for apparently similar material-environment combinations.

If the cracking results from cyclic loading of specific components, the applicant should justify

the use of the One-Time Inspection Program in lieu of periodic inspections, since such cracking

may have a long incubation period.

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By letter dated April 7, 2004; the applicant responded by stating that it identified SCC as an

AERM for EDG system stainless steel and copper alloy components in an air/gas.(wetted)

environment subject to elevat6d temperatures.. For stainless steels, the applicant utilized a

threshold temperature of 140 OF for susceptibility to SCC.. .

The applicant further stated that it determined that SCC is a potential aging effect for stainless

steels in the EDG exhaust system's air/gas (wetted) environment.- The. high temperature

exhaust gases produce the high elevated temperatures in the air/gas (wetted) environment

during EDG operation. These exhaust gases include water vapor and various corrosive

combustion products. The applicant does not expect SOC to actually occur, given the limited

number of times that each diesel generator is operated over the course of 60 years of plant

operation and the proximity of the exhaust temperatures to the threshold temperature for SCC.

However, the applicant stated that it does not have sufficient data to rule out the possibility of

the 'aging effect; therefore, it is prudent to perform a one-time inspection to assure that cracking

is not occurring; - ' -i

The applicant further stated that SCC is not an applicable aging effect for the stainless steels in

the' EDG intake system's air/gas (wetted) environment., The EDG intake system operates at

ambient temperatures and is not subject to'elevated temperatures. Table 3.3.2-15 of the LRA

should not have indicated cracking as an aging effect for the stainless steel ducts and fittings in

the EDG intake system.

The applicant stated that it determined that SCC is a potential aging effect for stainless steels

and copper alloys in portions of the EDG air. start system that are exposed to the air/gas

(wetted) environment with elevated temperatures. :Specifically, air exiting the compressors will

heat the downstream components. The one-time.inspection is specifically meant to examine

the inlet piping for the air receivers on the 1-2A EDG. The air start subsystem for this diesel

generator does not include an after cooler/air dryer assembly.: As such, potentially moist air at

temperatures above 140 0F could be in contact with the in-scope stainless steel and copper

alloy components. While the applicant does not consider SCC likely, the applicant stated that it

does not have suff icient data (the removal of the after cooler and air drier is a recent

modification) to rule out the possibility; therefore, the applicant stated that it is prudent to

perform a one-time inspection to assure that cracking is not occurring.-

Staff Evaluation of the Applicant's Response - ,' . ',Xa 1⁄4-i *;-

The staff reviewed the applicant's response to RAI 3.3.2.1.15-2. The staff finds the applicant's

response that SCC is not an applicable aging effect for the stainless steels in the EDG intake'

system's' air/gas (wetted) environment to be reasonable and acceptable because the applicant

has clarified-that the EDG intake system operates at ambient temperatures and is not subject to

elevated temperatures. Therefore, 1RA Table .3.3.2,15 should not have indicated cracking as

an aging effect for the stainless steel ducts and fittings in the EDG intake system.. However,

regarding the other parts of the applicant's responses, the staff requested the following

clarifications in order to complete the review. - -

- - ~ .

For stainless steels, the applicant utilized a threshold temperature of 140 'F for susceptibility to

SCC. The' applicant stated that the air start subsystem for this diesel generator does not..

include an after cooler/air dryer assembly. As such, according to the applicant, potentially moist

air at temperatures above 140 OF could be in contact with the in-scope stainless steel ard

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I

copper alloy components. Therefore, using the criterion adopted by the applicant, the,

component is susceptible to SCC. Yet the applicant considered that in this case SCC is

unlikely. In a telephone conference dated April 26, 2004, the staff asked the applicant to justify

this conclusion. If the component is susceptible to SCC, and SCC is likely to happen, then the

staff asked the applicant to justify the applicability of the One-Time Inspection Program.

The staff also asked the applicant to clarify its statement regarding "the proximity of the exhaust

temperatures to the threshold temperature for SCC." In particular, the staff asked the applicant

for clarification as to whether the exhaust temperature is above that of the threshold

temperature for SCC:

In the April 26, 2004, telephone conference and confirmed in a letter dated May 28, 2004, the

applicant responded to these comments regarding its initial response to RAI 3.3.2.1.15-2 dated

April 7, 2004. The applicant stated that the revised response to RAI 3.3.2.1.15-2 dated May 28,

2004, supersedes its response in SNC Letter No. NL-04-0473 dated April 7, 2004.

In its response, the applicant stated that the aging effect of cracking identified for the subject

components is associated with the aging mechanism of SCC and is not due to cyclic loading.,

Section 4.3.3 of the LRA addresses fatigue of'ASME non-Class 1 components separately as a

TLAA.

The applicant utilized a screening threshold temperature of 140 OF for assigning susceptibility to

SCC as an aging mechanism' (and cracking as the resultant aging effect) for stainless steel.

Stainless steels are susceptible to SCC in the presence'of detrimental species (e.g., halogens).

If oxygen is 'removed from the environment, cracking only occurs when concentrations of

detrimental species are very high. In general, industry experience and laboratory tests indicate

that SCC rarely occurs in stainless steels below 140 OF, unless the environment is harsh (e.g.,

significant contamination with halogens).

The applicant stated that no threshold temperature is associated with the susceptibility of -

copper alloys to SCC. Copper alloys (brasses) are susceptible to SCC from exposure to

ammonia and ammonium compounds. Both oxygen and moisture are necessary for ammonia

to be corrosive to copper alloys. -Bronzes, with the exception of aluminum bronze, are

considered immune to SCC. The applicant concluded that no threshold temperature is

associated with the susceptibility of copper alloys to SCC. However, lower contaminant levels

are required to initiate SCC in environments with elevated temperatures. The applicant

provided the clarifications for the following systems.

Emergency Diesel Generator' Exhaust System. The applicant stated that it determined that

SCC is a potential aging'mechanism/effect for- stainless steels in the EDG'exhaust system's

air/gas (wetted) environment.'- The; air/gas (wetted) environment includes elevated temperatures

(above the 140 0F threshold temperature) during EDG operation produced by the high

temperature exhaust gases.': These exhaust gases include'water vapor and various corrosive

combustion products. The applicant does not expect SCC to actually occur, given the

successful operating history of stainless steels in exhaust piping applications and the limited

operating time for each standby diesel generator. In addition, SNC did not identify any industry

or plant-specific operating experience indicative of SCC of stainless steels in a diesel exhaust

environment. The EDGs operate on standby, with the actual operating time comprised mainly

from surveillance and postmaintenance tests. 'The applicant clarified that a conservative

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ii
estimate of the actual operatirin time for each diesel generator is less than 5 to 10 percent of

the time over the course of 60 yea'rs, or 3 tot6 years of actual run time.

The applicant concluded that, since operating experience and actual operating time for the

EDGs indicate that SCC in the stainless steel exhaust components is unlikely, the use of the

One-Time Inspection Program is adequate to assure that cracking is not occurring. -

Emergency Diesel Generator Air Start Svstem. iThe applicant stated that it conservatively.

determined SCC to be a potential aging mechanism/effect for stainless steels and copper alloys

exposed to the air/gas (wetted) environmen't in portions of the EDG air start system. Only EDG

1 -2A has a configuratio where the air start'system gas is potentially wetted. The air start -

subsystem for'the 1 -2A EDG does not include anr after cooler/air dryer assembly. The air

exiting the compressors is nondried air at elevated temperatures (as a result of thecompression) and will heat the downstream components. After the system pressure is

achieved, the bompressor stops, the components cool down, and moisture can condense within

the comporients. Condensatiob/rnoisture is periodically drained from the system low points as

part of normal operating practice. - - -

In support of the LRA, the applicant measured the frequency of operation and temperature rise

in the 1-2A EDG air start system receiver charging piping. The air start system is operated

intermittently'during normal operation to marintain the pressure in the air receivers. The

initermittent operation' of the compressor occurs approximately six times a day,Alasts only a few

minutes, and raises the temperature just downstream of the compressor to as high as 215 -F,

with the' downstream temperature at the safety related receiver inlet isolation valve raised to as

high as 128 0F. In both locations, the temperature decreases quickly (the piping downstream of

the compressor falls below 140 OF in a feW minutes) and returns to the ambient room

temperature in about 1 hour.,

The applicant stated that on occasions such as during maintenance outages (estimated to be

once each refueling outage, equivalent to 40 times over a 60-year life), a full recharge of the air

receivers may be: required.' This process'takes approximately 1 hour. The manufacturer of the

compressor has stated that the discharge'teribperature of the air from the compressor could be

as high as 615 0F during a full recharge of the air receivers. Again, the temperature decreases

'fairly, quickly to room ambient temperatures once the charge is complete.-.-'

The applicant further stated that since the temperature exceeded the screening threshold

temperature of 140 'F, SCC was conservatively determined to be a potential aging

mechanism/effect for the stainless steel components However, based on operating

experience, the air start system is 'above 140 °F for a very small fraction of the time.. Coupled,

with the absence of any source'of contaminants,'SNC concluded that SCC of stainless steel in

the EDG air start system is very unlikely based on the'actual operating conditions for the EDG

air start system. -

The applicant clarified that the AMR also cons6rvatively determined that SCC of the copper

alloys in the EDG air start system downstream of the air receivers was a potential aging

mechanismj/effect. However, SNC'concludes that SCC of copper alloys (brass) in the EDG air

start system isvery unlikely since'there is no known source of ammonia or ammonium

compound contaminan'ts. '-! - -

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The applicant concluded that,. since the operating conditions (based on operating experience)

indicate that SCC in the stainless steel and copper alloys in the EDG air start system is very

unlikely, the use of the One-Time Inspection Program is adequate to assure that cracking is not

occurring.

The staff reviewed the applicant's responses and found the responses to be reasonable and

acceptable because (1) the applicant clarified that its operating experience and actual operating

time (5 to 10 percent of the time over the course of 60 years) for the EDGs indicate that SCC in

the stainless steel exhaust components is unlikely, and (2) the applicant also clarified that,

based on operating experience; the air start system is above 140 0F for a very small fraction of

the time and that the system environment does not have any source of contaminants, such that

SCC of stainless steel in the EDG air start system is very unlikely based on the actual operating

conditions for the EDG air start system.

During the scoping review, in a response to RAI 2.2-5a, the applicant provided an initial

response dated April 22,- 2004. By letter dated June. 10, 2004, the applicant provided a revised

response to the telephone conference of May 24, 2004, between SNC and NRC staff. The

applicant stated that this revised response supercedes its previous response in SNC Letter No.

NL-04-0678 dated April 22, 2004.

The applicant stated in its June 10,2004, letter that flexible hoses/connections and flexible,

joints in the OCCW and CCCW systems are made of carbon and stainless steel, are within the

scope, and are encompassed in the component type 'piping." These components are

constructed of the same materials as piping, exposed to the same internal and external

environments, experience the same aging affects, and are managed for aging by the same

programs. Table 2.3.3.5 for OCCW and Table 2.3.3.6 for. CCW include the component type

"piping." The intended function is pressure boundary. Table 3.3.2-5 for OCCW and Table

3.3.2-6 for CCCW also include the component type 'piping." Materials of construction include

both carbon steel and stainless steel.

The applicant further stated that, in the intake/exhaust subsystem of the EDG system, the

component type "ducts and fittings" includes the stainless steel expansion joints (as given in the

response to RAI 2.3.3.15-3). The original LRA omitted the other flexible hoses/connections and

flexible joints in the EDG system that are constructed of elastomers and are within the scope of

license renewal. Therefore, the applicant added the component type "flexible connectors" to

Tables 2.3.3.15 and 3.3.2-15.

The applicant indicated that flexible connectors exposed to closed-cooling water, air/gas

(wetted), lube oil, and inside environments are subject to a change in material properties,

cracking, and loss of material. It will manage these aging effects using the External Surface

Monitoring Program (Appendix B.5.3). The staff finds the applicant's response to RAI 2.2-5,

related to the AMR of the expanded scope, to be reasonable and acceptable because the

applicant stated that it will expand the scope of the External Surface Monitoring Program to

include elastomer. flexible connectors in the EDG system. -

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects of these EDG systemr

component types that are not addressed by the GALL Report are consistent with industry.

experience for these material-environment combinations. The staff did not identify any omitted

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aging effects. Therefore, the staff finds that the applicant has identified the appropriate aging

effects for the materials and environments associated with the ab6ve components in the EDG

system. '

Aging Management Programs - ;

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-15 of the LRA and the applicant's response to RAI 2.2-5a identify the following

AMPs for managing the aging effects described above for the EDG system:

* Water Chemistry Control Program (Appendix B.3.2)

* One-Time Inspection Program (Appendix B.5.5)

* Service Water Program (Appendix B.4.4)

* - External Surfaces Monitoring Program (Appendix B.5.3)

The applicant uses the Water Chemistry Control Program for managing the material aging

effect related to several different AERMs. The staff reviewed .the utilization of the Water

Chemistry Control Program in these different combinations of materials, environments, and

AERMs for the components in the EDG system. The staff finds this AMP adequate for

managing the identified aging effect because it is consistent both with the 10 attributes of the -

AMPs described in NUREG-1 801, Section XI.M2, and with the 10 attributes of the AMP

described in Section XI.M21, with the exception that FNP applies performance monitoring in

accordance with the EPRI guidelines for closed-cooling water. The effectiveness of these

GALL AMPs is consistent with industry experience. * -

The applicant uses the One-Time Inspection Program for managing the material aging effect

related to several different AERMs. The staff reviewed the 'utilization of the One-Time

Inspection Program in these different combinations of materials, environments, and AERMs for

the components in the EDG system. The staff finds this AMP adequate for managing the

identified aging effect because these aging effects are expected to occur at a relatively slow

rate.

The applicant uses the Service Water Program for managing fouling and loss of material in the

service water system and components. The staff reviewed the utilization of the Service Water

Program in these different combinations of materials, environments, and AERMs for the

components in the EDG system. The staff finds this AMP adequate for managing the identified

aging effect because it implements the recommendations of NRC GL 89-13 and is consistent

with the 10 attributes of the AMP described in NUREG-1 801, Section Xl.M20. The

effectiveness of this GALL AMP is consistent with industry experience.

The applicant credited the External Surfaces Monitoring Program with managing the aging.

effect of loss of material on copper alloy components exposed to an inside environment. The

staff reviewed the material, environment, and aging effects related to these components and

the adequacy of this AMP for managing the identified aging effect. The staff finds this AMP

adequate because it uses periodic inspections on the most susceptible components and

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I

locations to establish a baseline, trends the degradations, and takes corrective actions to,.;

prevent further degradations if such actions are warranted. The applicant has expanded the

scope of this AMP to include the flexible connectors elastomer components, as discussed in the

applicant's response to RAI 2.2-5a. The staff notes that, in the original description of the AMP

in LRA Section B.5.3.6, the applicant has stated that it will also inspect accessible in-scope

polymers or elastomers for age-related degradation.

Sections 3.0.3.2.1, 3.0.3.1, 3.0.3.2.5, and 3.0.3.3.2, respectively, of this SER document the

staff's detailed review of these-AMPs.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing th6e aging effects of the EDG system component types that are not

addressed by the GALL Report. In addition, the staff finds the program descriptions in the

FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the EDG system

components that are not addressed by the GALL Report, so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.3.2.3.16 Demineralized Water System

Summary of Technical Information in the Aoplication

In Section 3.3.2.1.16 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 demineralized water system:

* Water Chemistry Control Program

* One-Time Inspection Program

* External Water Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-16 of the LRA, the applicant provided a summary of AMRs for the demineralized

water system components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the demineralized water system components relating to those

combiriations of components, materials, environments, and AERMs and found them to beconsistent with the GALL Report. These combinations use notes A through E in LRA Table

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3.3.2-16. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMRs of the demineralized water system components relating to those

combinations of components, materials; environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-4. Section 3.3.2.1 of this SER documents the staff's evaluation. -

The staff reviewed the AMR of the demineralized water system relating to those combinations,

of components, materials, environments, and AERMs that are not addressed in the GALL

Report. These combinations use notes F through J in LRA Table 3.3.2-16. The staff.

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs for managing the AERMs. The staff also reviewed the applicable FSAR Supplements for

the AMPs to ensure that they adequately describe the AMPs.

Aging Effects

Table 2.3.3.16 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components that do not rely on the GALL Report for an:

AMR include piping and valve bodies.

For these component types, the applicant identified that stainless steel components exposed to

an inside environment do not experience any aging effects.

The staff reviewed the information in Section 2.3.3.16, Table 2.3.3.16, Section 3.3.2.1.16, and

Table 3.3.2-16 of the LRA. During its.review, the staff determined that it needed additional

information.

The staff organized its RAls into general RAls and system-specific RAls. General RAI 3.3-9

applies to this system. There are no relevant system-specific RAls.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAI 3.3-9. By letter dated April 7, 2004, the applicant

responded to this RAI. Section 3.3.2.3.0 of this SER describes this RAI, the applicant's

response, and the staff's evaluation of the response. ;

On the basis of its review of 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 demineralized water

system component types given above that are not addressed by the GALL Report are

consistent with industry experience for these material-environment combinations. The staff did

not identify any omitted aging effects. Therefore, the staff finds that the applicaht has identified

the appropriate aging effects for the materials and environments associated with the above

components in the demineralized water system., -

Aging Management Programs -. -

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program. -

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Table 3.3.2-16 of the LRA does not identify an AMP for managing the aging effects described

above for the demineralized water system.

On the basis of its review of the information provided in the LRA, the staff finds that no AMP is

needed for managing the aging effects of the demineralized water system component types

that are not addressed by the GALL Report.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and that no AMP is needed for managing the aging effects for the demineralized

water system components that are not addressed by the GALL Report, so that the intended

functions will be maintained consistent with the CLB for the period of extended operation; as

required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the'AMPs credited for managing aging in these components, as

required by 10 CFR 54.21(d).

3.3.2.3.17 High-Energy Line Break Detection System

Summary of Technical Information in the ApDlication

In Section 3.3.2.1.17 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 high-energy line break isolation system.

In Table 3.3.2-17 of the LRA, the applicant summarized the AMRs for the high-energy line

break isolation system components and identified which AMRs it considered to be consistent

with the GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the high-energy line break detection system components

relating to those combinations of components, materials, environments, and AERMs and found

them to be consistent with thle GALL Report. These combinations use notes A through E in

LRA Table 3.3.2-17. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the high-energy line break detection system relating to those-.

combinations of components,' materials, environments,'and AERMs that are not addressed in

the GALL Report. These combinations' use'notes F through J in LRA Table 3.3.2-17. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs for managing these effects. The staff also reviewed the applicable FSAR Supplements

for the AMPs to ensure that they adequately describe the AMPs.

Aging Effects

Table 2.3.3.17 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components that do not rely on the GALL Report for an

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AMR include piping and valve bodies.

For these component types, the applicant identified that stainless steel components exposed to

air/gas and inside environments do not experience any aging effects.

The staff reviewed the information in Section 2.3.3.17,-Table 2.3.3.17, Section 3.3.2.1.17, and

Table 3.3.2-17 of the LRA. During its review, the staff determined that it needed additional

information.

The staff organized its RAls into general RAls and system-specific RAls. General RAls

applicable to this system include RAls 3.3-7 and 3.3-9. There are no relevant system-specific

RAls for this system.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-7 and 3.3-9. By letter dated April 7, 2004, the

applicant responded to these RAls. Section 3.3.2.3.0 of this SER describe these RAls, the

applicant's'responses, and the staff's evaluation of the responses.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects of the high-energy line break

detection system component types given above that are not addressed by the GALL Report are

consistent with industry experience for these material-environment combinations. 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 high-energy line break detection system.

Aging Management Programs -:

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-17 of the LRA identifies no AMP for managing the aging effects described above

for the high-energy line break detection system.

On the basis of its review of the LRA, the staff finds that no AMP is needed for managing the

aging effects of the high-energy line break detection system component types that are not

addressed by the GALL Report. :

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and that no AMP is needed for managing the aging effects for the high-energy

line break detection system components that are not addressed by the GALL Report, so that

the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

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that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.3.2.3.18 Hydrogen Control System

Summary of Technical Information in the Application

In Section 3.3.2.1.1 8 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 hydrogen control system:

* One-Time Inspection Program

* External Surfaces Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-18 of the LRA, the'applicant summarized the AMRs for the hydrogen control

system components and identified which AMRs it considered to be consistent with the GALL

Report.

Staff Evaluation

The staff reviewed the AMRs of the hydrogen control system components relating to those

combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-18. Section 3.3.2.1 of this SER documents the staff's evaluation.

The technical staff reviewed the AMR of the hydrogen control system relating to those

combinations of components, materials, environments, and AERMs that are not addressed in

the GALL Report. These combinations use notes F through J in- LRA Table 3.3.2-18. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs for managing the AERMs. The staff also reviewed the applicable FSAR Supplements for

the AMPs to ensure that they adequately describe the AMPs.

Aging Effects

Table 2.3.3.18 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 equipment frames and housing, filters (casing), flow orifice/element, hydrogen

recombiner, piping, air sample analyzer, and valve bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Carbon steel in an air/gas environment is subject to the loss of material.

* Stainless steel exposed to air/gas, dried gas, or inside environments do not experience

any aging effects.

The staff reviewed the information in Section 2.3.3.18, Table 2.3.3.18, Section 3.3.2.1.1 8, and

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!I
Table 3.3.2-18 of the LRA. During its review,' the staff determined that it needed additional

information. - -

The staff organized its RAls into general RAls and system-specific RAls. General RAI 3.3-9

applies to this system. There are no relevant system-specific RAls.

By letter dated March 8, 2004, the staff requested the applicant'to provide additional

information on the issues described in RAI 3.3-9. By letter dated April 7, 2004, the applicant

responded to this RAI. _Sectio'n-3.3.2.3.0 of this SER describes this RAI, the applicant's

response, and the staff's evaluation of the response."

On the basis'of its review of 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 hydrogen control system

component types given above that are not addressed by the GALL Report are consistent with

industry experience for these material-environment combinations.:4The'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

hydrogen control system.

Aging Management Program

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-18 of the LRA identifies the One-Time'Inspection Program (B.5.5) for managing the

aging effects described above for the hydrogen 'control system.

The applicant uses the One-Time Inspection' Program for managing the aging effect of loss of

material for carbon steel exposed to an air/gas environment in the hydrogen control system.

The staff finds this AMP adequate for managing the identified aging effect because this aging effect is expected to occu'r at a relatively slow rate:.

Section 3.0.3.1 of this SER provides the staff's detailed review of this AMP.

On the basis of its review of the LRA, the staff finds that the applicant has identified an

appropriate AMP for managing the aging effects of the hydrogen control system component

types that are'not addressed by the GALLReport.' In addition, the staff finds the program

description inithe FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effect, and the AMP credited for managing the aging effect, for the hydrogen control

system components'that are not addressed by the GALL Report, so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

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I

The staff also reviewed the applicable FSAR Supplement program summaries and concludes.

that they adequately describe the AMP credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.3.2.3.19 Liquid Waste and Drains

Summary of Technical Information in the Application

In Section 3.3.2.1.19 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 liquid waste and drains:

* Water Chemistry Control Program

* One-Time Inspection Program

* External Water Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-19 of the LRA, the applicant summarized the AMRs for the liquid waste and

drains components and identified which AMRs it considered to be consistent with the GALL

Report.

Staff Evaluation

The staff reviewed the AMRs of the liquid waste and drains system components relating to

those combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-19. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the liquid waste and drains system relating to those

combinations of components, materials, environments, and AERMs that are not addressed in

the GALL Report. These combinations use notes F through J in LRA Table 3.3.2-19. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs for managing these effects. The staff also reviewed the applicable FSAR Supplements

for the AMPs to ensure that they adequately describe the AMPs.

Aging Effects

Table 2.3.3.19 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components that do not rely on the GALL Report for an

AMR include closure bolting, flexible connectors, floor drain plug, piping, tanks and valve

bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Elastomer components exposed to inside or wetted air/gas environments are subject to

the aging effects of change in material properties, cracking, and loss of material.

* Carbon steel and alloy steel components exposed to wetted air/gas, lube oil, inside, or

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iH
raw water environments are subject to the loss of material aging effect.

* Galvanized steel exposed to wetted air/gas or inside environments are subject to the

- loss of material aging effect. '

* - -Stainless steel components exposed to lub6 oil, borated water, or raw water

environments are subject to the loss of material aging effect. -

* -Stainless steel components exposed to inside environments experience no aging -

effects. -"-l.. -

The staff reviewed the information in Section 2.3.3.19, Table 2.3.3.19, Section 3.3.2.1.19, and -

Table 3.3.2-19 in the LRA. During its review, the staff determined that it needed additional

information.

The staff organized its RAls into general RAIs and system-specific RAls. General RAls

applicable to this system include RAls 3.3-6,3.3-10,-3.3-11, and 3.3-16. -. ; -

By letter dated March 8,2004, the staff requestedthe applicant to provide additional

information on the issues described in RAls 3.3-6, 3.3-10, 3.3-11, and 3.3-16. By letter dated

April 7, 2004, the applicant responded to these RAls. Section 3.3.2.3.0 of this SER describe

these RAls, the applicant's responses and the staff's evaluation of the responses. -

By the same letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in system-specific RAI 3.3.2.1.19-1. By letter dated April 7,

2004, the applicant responded to this RAI. The following describes RAI 3.3.2.1.19-1, the

responses to this RAI, and the staff's evaluation of the responses.-

Cracking Initiation and Growth Not Identified as a Plausible Aging Effect for Stainless Steel

Components Exposed to Borated Water Environment (RAI 3.3.2.1.19-1). Crack initiation and

growth are plausible aging effects for stainless steel components exposed to a borated water -

environment. However, LRA Table 3.3.2-19 did not identify this as a plausible aging effect for

stainless steel piping and valve bodies. 'The staff asked the applicant to provide the technical

basis for excluding these plausible aging effects.

In response, by letter dated April 7,2004, the applicant stated that it applied a conservative

threshold temperature of 140 OF for the initiation of SCC in austenitic stainless steel -l --

components exposed to borated water.-:Extensive industry data based on actual operating

experience and laboratory testing indicate that initiation of SCC is unlikely to occur at,;

temperatures less than 140 OF unless the materials are sensitized and exposed to harsh marine

wet/dry cycling conditions. This SCC threshold limit is consistent with EPRI TR-i 003056..

The applicant further stated that the in-scope liquid waste and drains components exposed to a

borated water environment operate at temperatures less than the i40 OF threshold temperature

and, therefore, the applicant did not include this aging effect in Table 3.3.2-19.* -

The staff reviewed the applicant's response to RAI 3.3.2.1.19-1 and found the response to be

reasonable and acceptable because' the applicant indicated that in-scope liquid waste and

drains components exposed to a borated water environment operate at temperatures less than

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the 140 OF threshold temperature, and this threshold temperature for the occurrence of SCC is

consistent with industry data and experience.

During the scoping review, in a response to RAI 2.3.3.19-4, the applicant added two portions of

the drainline in the liquid waste and drains system. One portion of the drainline is made from

cast iron, and the remainder, where the line enters the sump,' is made from the stainless steel.

Both portions of the drainline are embedded in concrete. The applicant stated that its

evaluation did not identify' any credible aging effects that could potentially result in a failure of

the drain piping and surrounding concrete to direct flow to the sump. Therefore, no additional

AMPs are required. The applicant revised LRA Table 3.3.2-19 to reflect the above changes in

scope for the AMR. The staff finds the applicant's response to RAI 2.3.3.19-4, with respect to

an AMR, to be reasonable and acceptable because (1) the drainline is sloped to prevent water

pooling, (2) leakage in the room is normally insignificant, and (3) this line is dry during normal

operating conditions.

During the scoping review, in a supplemental response (Part 2) to RAI 2.1-1 dated June 4,

2004, the applicant added component types, including drain bodies and pump casings, to LRATable 2.3.3.19 and added tanks (waste holdup and floor drain tanks), piping and components

(drain piping' including floor drain bodies), pump casings (sump pumps), and drain bodies (roof

drains) to LRA Table 3.3.2-19.

For these component types, the applicant identified additional mnaterials, environments, and

AERMs. Stainless steel components exposed to raw water (including untreated), cast iron

components exposed to an outside&environnment, or stainless'steel and copper alloys'

components exp6oedto an-air/gas (wetted) environment are subject to the loss of material

aging effect. For these component types, the applicant' uses the' One-Time lnspection Program

to manage this aging effect. The applicant also noted that th6 stainless steel and copper alloys

components exposed to an inside environment, or cast iron components exposed to an

embedded environment, experience no aging effects and require no AMPs.

The staff finds the applicant's supplemental response (Part 2) to RAI 2.1 -1, related to liquid

waste and drains including roof drains and sainitary drains, to be reasonable and acceptable

because all the identified aging effects will be adequately managed.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects'of the liquid waste and drains

component types given above that are not addressed by the GALL Report are consistent with

industry experience for these material-environment combinations. The 'staff did not identify any

omitted aging effects. Therefore, the staff finds that the applicant has identified the appro6riate

aging effects for the materials and environments associated with the above liquid waste and

drains components.

Aging Management Programs

After evaluating the applicant's identification of aging effects for' each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

agin' effects. The staff also determined that the FSAR Supplement adequately describes the''

program.

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Table 3.3.2-19 of the LRA identifies the following AMPs for managing the aging effects

described above for liquid waste and drains components:

* Water Chemistry Control Program (Appendix B.3.2); {.-

* - ~ Borated Water Leakage Assessment and Evaluation Program (Appendix B.3.5)

* - External Surfaces Monitoring Program (Appendix B.5.3) -

* One-Time Inspection Program (Appendix B.5.5) . -

The applicant credited the Water Chemistry Control Program with managing the loss of material

in the stainless steel piping and valve bodies'exposed to borated water. During its review, the

staff determined that it needed additional information and requested it in RAI 3.3-10. Section

3.3.2.3.0 of this SER describes RAI 3.3-10, the applicant's response to this RAI, and the staff's

evaluation of the responses. - - -K

The applicant credited the Borated Water Leakage Assessment and Evaluation Program with

managing effects of the loss of material due to boric acid corrosion on carbon steel or'alloy

steel components exposed to an inside environment. The staff reviewed the material,.

environment, and aging effects on these components and finds that this AMP is adequate for,

managing the identified aging effects because it is consistent with the Boric Acid Corrosion

Program in the GALL Report. The effectiveness of the GALL program is consistent with

industry experience.

The applicant credited the External Surfaces Monitoring Program with managing the loss of

material on carbon steel or alloy steel components exposed to an inside environment. -The staff

reviewed the material, environment, and aging effects on these components, as well as the

adequacy of this AMP to manage the identified aging effect. The staff finds this AMP adequate

because it uses periodic inspections on the most susceptible components and locations to

establish a baseline, trends the degradations, and takes corrective actions to prevent further

degradations if such actions are warranted. The applicant has expanded the scope of this AMP

to include the flexible connectors and floor drain plug elastomer components, as discussed in

the applicant's response to RAI 3.3-6 in Section 3.3.2.3.0 of this SER. The staff notes that, in

the original description of the AMP in LRA Section B.5.3.6, the applicant stated that it will also

inspect the accessible in-scope polymers or elastomers for age-related degradation.

The applicant used the One-Time Inspection Program to manage material aging effects related

to several different AERMs.' The staff reviewed the utilization of the One-Time Inspection

Program in these different combinations of materials, environments,-and AERMs for the liquid

waste and drains components and finds this AMP adequate for managing the identified aging

effect because these aging effects are expected to occur at a relatively slow rate.-

Sections 3.0.3.2.1, 3.0.3.1.1, 3.0.3.3.2, and 3.0.3.1 of this SER, respectively, provide the staff's

detailed review of these AMPs.

On the basis of its-reviewof the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of Ithe liquid waste and drains component types that are.

not addressed by the GALL Report. *In addition,jthe staff finds the program descriptions in the

FSAR Supplement acceptable.

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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 for managing the aging'effects, for the liquid waste and

drains components that are not addressed by the GALL Report, so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21(d).

3.3.2.3.20 Oil-Static Cable Pressurization System

Summary of Technical Information in the Application

In Section 3.3.2.1.20 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 oil-static cable pressurization system:

* External Surfaces Monitoring Program

* Buried Piping and Tank Inspection Program

In Table 3.3.2-20 of the LRA, the applicant summarized the AMRs for the oil-static cable

pressurization components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the oil-static cable pressurization system components relating

to those combinations of components, materials, environments, and AERMs and found them to

be consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-20. Section 3.3.2.1 of this SER documents the staff's evaluation.

The technical staff reviewed the AMR of the oil-static cable pressurization system relating.to

those combinations of components, materials, environments, and AERMs that are not- -

addressed in the GALL Report. These combinations use notes F through J in LRA Table 3.3.2-

20. The staff determined that the applicant has identified all applicable AERMs and has

credited appropriate AMPs for managing these effects. The staff also reviewed the applicable

FSAR Supplements for the AMPs to ensure that they adequately describe the AMPs.

Aging Effects

-Table 2.3.3.20 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 piping, pump casings, tanks, and valve bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

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* Carbon steel exposed to buried, inside, and outside environments is subject to the loss

of material.';-,-

* Elastomersexposed to an inside environm 'ent are subject to a change in material

properties, cracking, and loss of material:

* Copper alloy exposed to an outside environment is subject to a loss of material.

The LRA does not identify any AERMs for carbon steel exposed to dried gas or lube'oil;

stainless steel exposed to dried gas; lube oil, or inside environments; copper alloy exposed to

lube'oil or inside environments; or elastorriers exposed to dried gas. :-

The staff reviewed the information in Section 2.3.3.20, Table 2.3.3.20, Section 3.3.2.1.20, and

Table 3.3.2-20 of the LRA. During its review, the staff determined that it needed additional

information. -

The staff organized its RAls into general RAls and system-specific RAls. General RAIs

-applicable to this system include RAls 3.3-9, 3.3-11, and 3.3-14. There are no relevant systemspecific RAls.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-9, 3.3-11, and 3.3-14. By letter dated April 7,

2004, the applicant responded to these RAls. Section 3.3.2.3.0 of this SER provides these

RAls, the applicant's responses, and the staff's evaluation of the responses.

On the basis'of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects of the oil-static cable

pressurization system component types given above that are not addressed by the GALL

Report are consistent with industry experience for these material-'environment combinations.

The staff did not identify any omitted aging effects. Therefore, the staff finds that the applicant

has identified the'appropriate aging effects for thee rnaterials and environments associated with

the above components in the oil-static cable prressurization system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they'are'appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program. -

Table 3.3.2-20 of the LRA identifies the following AMPs for managing the aging effects

described above for the oil-static cable pressurization system:

* External Surfaces Monitoring Program (AppendixB.5.3)

* Buried Piping and Tank Inspection Program (Appendix B.5.4)

The applicant credited the External Surfaces Monitoring Program with managing the loss of

material on carbon steel, or alloy steel components exposed to inside and outside I - - .

environments. It is also credited with managing the loss of material, cracking, and changes in

material properties in elastomer flexible hoses used in the oil-static cable pressurization system.

The staff reviewed the material, environment, and aging effects related to these components

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and the adequacy of this AMP for managing the identified aging effect. The staff finds this AMP

adequate because it uses periodic inspections of the most susceptible components and

locations to establish a baseline, trends the degradations, and takes corrective actions to

prevent further degradations if such actions are warranted. -

The applicant credited the Buried Piping and Tank Inspection Program with managing the loss

of material on carbon steel components exposed to a buried environment. The staff reviewed

the material, environment, and aging effects related to these components and the adequacy of

this AMP for managing the identified aging effect. The staff finds this AMP adequate because it

is consistent with NUREG-1 801, Section XL.M34, with the exceptions that were found to be

acceptable in Section 3.3.2.3.5 of this SER.

Sections 3.0.3.3.2 and 3.0.3.2.10 (see also 3.3.2.3.5) of this SER, respectively, provide the

staff's detailed review of these AMPs.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the oil-static cable pressurization system component

types that are not addressed by the GALL Report. In addition, the staff finds the program

descriptions in the FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the oil-static cable

pressurization system components that are not addressed by the GALL Report, so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.3.2.3.21 Potable and Sanitary Water System

Summary of Technical Information in the Application

In Section 3.3.2.1.21 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 potable and sanitary water system:

* One-Time Inspection Program

* External Surfaces Monitoring Program

In Table 3.3.2-21 of the LRA, the applicant summarized the AMRs for the potable and sanitary

water system components and identified which AMRs it considered to be consistent with the

GALL Report.

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Staff Evaluation - '

The staff reviewed the AMRs of the potable&and sanitary'water system components relating to

those combinations of components, materiailsenvironments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-21. Section 3.3.2.1 of thisSER documr'nernts the staff's evaluationn.;'

The staff reviewed the AMR of the potable and sanitary water system relating to those

combinations of components, materials,'environments, and AERMs that are not addressed in

the GALL Report. These combinations'use notes F through J in LRA Table 3.3.2-21. -The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs for managing these effects. The staff also reviewed the applicable FSAR Supplements

for the AMPs to ensur&'that they adequately describe 'the AMPs.' -

Aging Effects

Table 2.3.3.21 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components that do not rely on the GALL Report for AMR

include closure bolting, heat exchanger (chiannel head), heat exchanger (shell), piping,

strainers, tanks, and valve bodies. ' -

For these component types, the applicant identified the following materials, environments, and

AERMs ' -':

Alloy steel components exposed to an inside environment are subject to the aging effect

of loss of material. - -

-- ' -'' ' ;'1 . ! , .;i

* Copper alloy components exposed to a raw water environment are subject to the loss of

material aginfg effect. -

* Carbon steel components exposed to treated water or inside environments are subject

to the loss of material aging effect.

'Stainless steel components exposed to a raw water environment are subject to the loss

of material aging effect. -

* Stainle'ss-steel exposed to an inside environment experiences no aging'effects.; -I . _ a ... I ,]t S , , . .- '

The staff reviewed the inforration'in Section 2.3.3.21, Table 2.3.3.21, Section 3.3.2.1.21,--and

Table 3.3.2-21 of the LRA. During 'its revi6w,'the staff determined that it needed additional -.

information. . - -

*,, , ,; - , - , K,; - ; ; 

The staff organized its RAls into general RAls and system-specific RAls. -General RAls

applicable to this system include RAls 3.3-11 and 3.3-16.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on'the'issiife described in RAls 3.3-11 and 3.3-16. By letter dated April 7, 2004, ;

the applicant responded to these' RAls. Section 3.3.2.3.0 of this SER describe these RAls, the

applicant's responses, and the staff's evaluation of the responses.

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By the same letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in system-specific RAI 3.3.2.1.21-1. By letter dated April 7,

2004, the applicant responded to this RAI. The following describes RAI 3.3.2.1.21-1, the

responses to this RAI, and the staff's evaluation of the responses.

Selective Leachina Not Identified as a Plausible Aging Effect for Copper Alloy Components

Exposed to Raw Water (RAI 3.3.2.1.21-1). Selective leaching is a plausible aging effect for

copper alloy components exposed to raw water. However, LRA Table 3.3.2-21 does not

identify this aging effect for the potable and sanitary water system for the copper alloy piping

and valve bodies exposed to raw water. The staff asked the applicant to provide the technical

basis for excluding this aging effect.

By letter dated April 7, 2004, the applicant responded. Selective leaching is the removal of one

element from a solid alloy by corrosion processes, such as the removal of zinc from brass

alloys. Copper alloys containing zinc in quantities greater than 15 percent are susceptible to

selective leaching. The addition of small amounts of alloying elements such as tin also inhibit

selective leaching.

The applicant stated that it purchased the copper alloy piping exposed to raw water in the

potable and sanitary water system to ASTM B-88, Type L, specifications. This material is 99.9

percent copper, which is not susceptible to selective leaching.

The applicant further stated that it purchased the copper alloy valve bodies exposed to raw

water in the potable and sanitary water system to ASTM B-62 specifications. This material

contains zinc in quantities of less than 15 percent (specification is 4.0-6.0 percent). The

inclusion of 4.0-6.0 percent tin also inhibits this effect in this material. Therefore, the applicant

concluded that these valve bodies are not susceptible to selective leaching.

In summary, the applicant stated that the copper alloy piping and valve bodies in the potable

and sanitary water system that are exposed to raw water are not susceptible to selective

leaching; therefore, the applicant did not identify this aging effect in LRA Table 3.3.2-21.

The staff finds the applicant's response to RAI 3.3.2.1.21-1 to be reasonable and acceptable

because the applicant has clarified that the composition of the copper-based materials is such

that they are not susceptible to selective leaching when exposed to raw water.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects of the potable and sanitary

water system component types given above that are not addressed by the GALL Report are

consistent with industry experience for these material-environment combinations. 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 potable and sanitary water system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

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i:
program.

Table 3.3.2-21 of the LRA identifies'the followving AMPs for managing the aging effects

described above for the potable and sahitaiyviatf i system:

* External Surfaces Monitoring Program (Appendix B.5.3)

* One-Time Inspection (Appendix B.5.5)

The applicant credited the External Surfaces Monitoring Program with managing the loss of

material on carbon steel components exposed to an inside environment. The staff reviewed the

material, environment, and aging effects related to these components and finds this AMP

adequate for managing the identified aging effect because it uses periodic inspections on the

most susceptible components and locations to establish a baseline, trends the degradations,

and takes corrective actions to prevent further degradations if such actions are warranted.

The applicant uses the One-Time Inspection Program to manage the material aging effect,-

related to several different AERMs. The staff reviewed the utilization of the One-Time

Inspection Program in these different combinations of materials, environments, and AERMs for

the components in the portable and sanitary water system and finds that this AMP,-is adequate

for managing the identified aging effect because these aging effects are expected to occur at a

relatively slow rate. tSections 3.0.3.3.2, and 3.0.3.1 of this SER, respectively, detail the staff's review of these

AMPs.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the potable and sanitary water system component

types that are not addressed by the GALL Report. In addition, the staff finds the program

descriptions in the FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the potable and

sanitary water system components that are not addressed by the GALL Report, so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10'CFR 51.21 (a)(3).

The staff also reviewed the applicabl6 FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.3.2.3.22 Radiation Monitoring System

Summary of Technical Information in the ArPlication. -

In Section 3.3.2.1.22 of the LRA, the applicant stated that it included radiation monitoring -

system mechanical components requiring AMR as part of the LRA systems for the process and

effluents being monitored.

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I

Staff Evaluation

In Section 2.3.3.22 of the LRA, the applicant stated that no components are subject to an AMR

for the radiation monitoring system. Section 2.3.3.22 of this SER details the staff's evaluation

on the discussion of scoping and screening results for the radiation monitoring system.

Conclusion

Section 2.3.3.22 of this SER details the staff's evaluation of the radiation monitoring system.

3.3.2.3.23 Reactor Makeup Water Storage System

Summary of Technical Information in the Application

In Section 3.3.2.1.23 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 makeup water storage system:

* Water Chemistry Control Program

* One-Time Inspection Program

* External Surfaces Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-23 of the LRA, the applicant summarized the AMRs for the reactor makeup water

storage system components and identified which AMRs it considered to be consistent with the

GALL Report.

Staff Evaluation

The staff reviewed the AMRs of the reactor makeup water storage system components relating

to those combinations of components, materials, environments, and AERMs and found them to

be consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-23. Section 3.3.2.1 of this SER documents the staff's evaluation.

The staff reviewed the AMR of the reactor makeup water storage system relating to those

combinations of components, materials, environments, and AERMs that are not addressed in

the GALL Report. These combinations use notes F through J in LRA Table 3.3.2-23. The staff

determined that the applicant has identified all applicable AERMs and has credited appropriate

AMPs for managing these effects. The staff also reviewed the applicable FSAR Supplements.

for the AMPs to ensure that they adequately describe the AMPs.

Aging Effects

Table 2.3.3.23 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components that do not rely on the GALL Report for an

AMR include closure bolting, flow orifice/element, piping, pump casings, tanks, and valve

bodies.

For these component types, the applicant identified the following materials, environments, and

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II
AERMs:

* Alloy steel and carbon steel components exposed to inside or outside environments are

subject to the loss of material.

* Carbon steel components exposed to a treated water environment are subject to the

loss of material.

* Stainless steel components exposed to a treated water environment are subject to the

loss of material. : - -

* Stainless steel components exposed to inside or outside environments experience no

aging effects. -

The staff reviewed the information in Section 2.3.3.23, Table 2.3.3.23, Section 3.3.2.1.23, and

Table 3.3.2-23 of the LRA. During its review, the staff determined that it needed additional

information.- -

The staff organized its RAls into general RAls and system-specific RAls. General RAIs

applicable to this system include RAls 3.3-1 0, .3.3-1 1 and 3.3-16.

By letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in RAls 3.3-10, 3.3-11, and 3.3-16. By letter dated April 7,

2004, the applicant responded to these RAls." Section 3.3.2.3.0 of this SER describe these .-

RAIs, the applicant's responses and the staff's evaluation of the responses.

By the same letter dated March 8, 2004, the staff requested the applicant to provide additional

information on the issues described in system-specific RAI 3.3.2.1.23-1. By letter dated April 7,

2004, the applicant responded to this RAI. The following describes RAI 3.3.2.1.23-1, the

response to this RAI, and the staff's evaluation of the response.

Exclusion of the SCQ Aging Effect for Stainless Steel or Carbon Steel Comronents Exposed to

Treated Water (RAI 3.3.2.1:23-1). Crack initiation and growth due to SCC may be a plausible

aging effect on stainless steel and carbon steel exposed to treated water. -However, the LRA

does not identify this aging effect on any-of the stainless steel or carbon steel components

exposed to treated water in the reactor makeup water storage system. The staff asked the

applicant to provide the technical basis for excluding this aging effect for the stainless steel or

carbon steel components exposed to treated water.

By letter dated April 7, 2004, the applicant responded to RAI 3.3.2.1.23-1 by providing the

following information. - - l : -

Stainless Steel -

The applicant stated that it applies a conservative threshold temperature of 140 0F for the

initiation of SCC in stainless steel components exposed to borated water. Extensive industrydata based on actual operating experience and laboratory testing indicate that the initiation of

SCC is unlikely to occur at temperatures less than 140 OF unless the materials are sensitizedand exposed to harsh marine wet/dry cycling conditions. This SCC threshold limit is consistent

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I

with EPRI TR-1003056.

The applicant further stated that the Water Chemistry Control Program manages the reactor

makeup storage water system borated water chemistry, which operates at temperatures less

than 140 OF. Therefore, the applicant concluded that SCC is not a potential aging mechanism

for stainless steel components in this system.

Carbon Steel

The applicant stated that, for carbon steel and alloy steel, EPRI TR-1 003056 only identifies

SCC as potential aging mechanism when nitrate corrosion inhibitors are utilized. However,

FNP does not use' nitrate inhibitors in the reactor makeup water system (treated water

environment). Therefore, the applicant concluded that SCC is not a potential aging mechanism

for carbon and alloy steel components in this system.

The staff reviewed the applicant's response to RAI 3.3.2.1.23-1 and found it to be reasonable

and acceptable because the applicant clarified that (1) the reactor makeup storage water

system borated water operates at temperatures less than 140 OF, the threshold temperature for

the initiation of SCC in stainless steel components exposed to borated water, which is

consistent with industry data based on actual operating experience and laboratory testing, and

(2) FNP does not use nitrate inhibitors in the reactor makeup water system (treated water

environment).

As a follow-up to SNC's response to RAI 2.3.3.23-1' provided in SNC Letter No. NL-04-0678

dated April 22, 2004, the staff'requested SNC to discuss whether disintegration of the

diaphragm membrane can cause blockage of the supply lines from the reactor makeup water

storage tanks to the CCW system. In its response dated June 18,2004, by SNC Letter No. NL04-1038, the applicant added tank diaphragms (reactor makeup water storage tanks) to Tables

2.3.3.23 and 3.3.2-23. The applicant indicated that elastomers exposed to treated water or

air/gas (tank air space) are subject to a change in material properties, cracking, and loss of

material. The applicant will use a new AMP, Periodic Surveillance and Preventive Maintenance

Activities (B.5.9) to manage these aging effects. -The staff. finds the applicant's follow-up

response to RAI 2.3.3.23-1 to be reasonable and acceptable because this new AMP will provide

for periodic component inspections and testing to detect aging effects or component

degradation before the loss of intended functions occurs.

As a result of the scoping and screening inspection conducted by NRC Region II from May

10-14, 2004, and documented in NRC Inspection Reports 50-348/2004-07 and

50-364/2004-07, dated June 22, 2004, the inspectors noted that the scope of license renewal

did not include the atmospheric vents on several tanks. In its letter'dated July 9, 2004, the

applicant included the vents for the reactor makeup water storage tanks within the scope of

license renewal and added the stainless steel reactor makeup water storage tank (including

tank vent) into LRA Table 3.3.2-23 for an AMR. The applicant stated that, for the reactor

makeup water storage tanks which have internal diaphragms, it applied the air/gas (nonwetted)

environment to these'vents because they are not exposed to high moisture (humidity) from the

tank's water contents because of the protective internal diaphragm., The applicant concluded

that there is no aging' effect for this material-environment combination for this component;

therefore, it requires no AMP. Because stainless steel components'exposed to nonwetted

air/gas environments do not experience any AERMs, the staff finds the applicant's assessment

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of the aging effectst related to this added component to be reasonable and acceptable.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that'the'aging effects of the reactor makeup water.,

storage system component types given above that are not addressed by the GALL Report are

consistent with industry experience for these material-environment combinations. 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 reactor makeup water storage system.

Aging'Management Programs -

After evaluating the applicant's identification'of aging'effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-23 of the'LRA and the applicant's follow-up'response, dated June 18, 2004, to RAI

2.3.3.23-1 'identify the following AMPs for managing the aging effects described above for the -

reactor makeup water storage system: - . ta : -.

* Water Chemistry Control Program (Appendix B.3.2) -

* External Surfaces Monitoring Program (Appendix B.5.3)

* - One-Time Inspection (Appendix B.5.5)

* Periodic-Surveillance-and Preventive Maintenance Activities (Appendix B.5.9)

The applicant credited the Water Chemistry Control Program with managing the loss of material

aging effect on the stainless steel piping, flow elements, orifices, and valve bodies exposed to

treated water. During its review, the staff determined that it needed additional information,

requested in RAI 3.3-10. Section 3.3.2.3.0 of this'SER describes RAI 3.3-10, the applicant's

response to this RAI, and the staff's evaluation of the response.

The applicant credited the External Surfaces Monitoring Program with managing the loss of

material on carbon steel components exposed to an inside environment.' The staff reviewed the

material, environment, and aging effects related to these components and the adequacy of this

AMP for managing the identified aging effect. The staff finds this AMP adequate because it

uses periodic inspections of the most susceptible components and locations to establish a

baseline, trends the degradations, and takes corrective actions to prevent further degradations

if such actions are warranted.

The applicant uses the One-Time'Inspection Program to manage the material aging effect..

related to several different AERMs. The staff reviewed the utilization of the One-Time - Inspection Program in these different combinations of materials, environments, and AERMs for

the components in the reactor makeup water storage system and finds that this AMP, pending

satisfactory resolutions of the RAls, is adequate for managing the identified aging effect

because these aging effects are expected to occur, at a relatively slow rate. -

The Periodic Surveillance and Preventive Maintenance Activities program is a condition

monitoring program. It includes those preventive maintenance and surveillance testing

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activities credited with managing the aging effects identified in the AMRs. The staff reviewed

the utilization of this program for the reactor makeup water storage tank diaphragm inspections

for managing change in material properties, cracking, and the loss of material on the internal - -

elastomer diaphragms in these tanks;- The staff finds this AMP adequate because the applicant

stated that the extent and schedule of inspections will assure detection of component

degradation before the loss of intended functions occurs. -

Sections 3.0.3.2.1, 3.0.3.3.2, 3.0.3.1, and 3.0.3.3.4 of this SER, respectively, detail the staff's

review of these AMPs.

On the basis of its review of the LRA, the staff finds the applicant has identified appropriate

AMPs for managing the aging effects of the reactor makeup water storage system component

types that are not addressed by the GALL Report. In addition, the staff finds the program

descriptions in the FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the reactor makeup

water storage system components that are not addressed by the GALL Report, so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.3.2.3.24 Sampling System --

Summary of Technical Information in the Application

In Section 3.3.2.1.24 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 sampling system:

* Water Chemistry Control Program

* External Surfaces M6nitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.3.2-24 of the LRA, the applicant provided a summary of the AMRs for the sampling

system components and identified which AMRs it considered to be consistent with the GALL

Report.

Staff Evaluation

The staff reviewed the AMRs of the sampling system components relating to those

combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.3.2-24. Section 3.3.2.1 of this SER documents the staff's evaluation.

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The staff reviewed the'AMR of the samipling system relating to those combinations of

components, materials, environments, and AERMs that are not addressed in the GALL Report.

These combinations use'notes F through J in LRA Table 3.3.2-24.- The staff determined that

the'applicant has identified all'applicable AERMs and has credited appropriate AMPs for.

managing these effects.' The staff also reviewed the applicable FSAR Supplements for the

AMPs to-ensure that they adequately describe the AMPs.

Aging Effects

Table 2.3.3.24 of the LRA lists individual system components within the scope of license

renewal 'and subject to an AMR. The componienits that do not rely on the GALL Report for an -

AMR include sample cooler heat'exchanger (tubes), piping, and valve bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Stainless steel components exposed to borated water, closed cooling water, or treated

waterenvironments are'subject to' the aging effects of loss of material and cracking..*- - , ~~~. , [ -, . -,;,I , . ,-, .- .,;.. ..

* Stainless steel exposed to an inside environment experiences no aging effects.-

The staff reviewed the information in Section 2.3.3.24, Table 2.3.3.24, Section 3.3.2.1.24, and.

Table 3.3.2-24 in the LRA. During its review, the staff determined that it needed additional

information.

The staff organized its RAls into general RAls and system-specific RAls.- General RAls

applicable'to this system include RAls 3.3-10 and 3.3-15. - -- -

By letter dated March 8, 2004, the staff requested the applicant to provide additional.

information on the issues described in RAls 3.3-10 and 3.3-15. By letter dated April 7, 2004,

the applicant responded to these RAls.' Section 3.3.2.3.0 of this SER describe these RAIs, the

applicant's responses, and the staff's evaluation of the responses.-

By the same letter dated March 8, 2004, the'staff requested the applicant to provide additional

information on the issues described in system-specific RAI 3.3.2.1.24-1. By letter dated April 7,

2004, the applicant responded to this RAI. The following describes RAI 3.3.2.1.24-1, the

responses to-this RAI, and the staff's evaluation of the responses.

Heat Exchanper Tube Function of the Sampling System (RAI 3.3.2.1-:24-1). Table 2.3.3.24 of

the LRA states that an intended function of the sampling system heat exchanger tubes is to

exchange heat. The tubes may be subject to the buildup or deposit of fouling or other

degradation that would result in a loss of this'heat exchange function; however, the LRA does

not identify this aging effect for the heat exchanger tubes in this system. The staff asked the

applicant to provide the technical basis for excluding this aging effect on the heat exchangers.

By letter dated April 7,'2004,-the applicant responded to RAI 3.3.2.1.24-1 by stating that SNC

erred in applying the intended function of heat exchange to the sample cooler tubes. The

sample coolers in the sampling system support the fire protection regulated event

(10 CFR 50.48) and, therefore, are within the scope of license renewal according to

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10 CFR 54.4(a)(3). The applicant credited manual sampling of certain parameters to verify

achievement of an adequate cold shutdown margin in the fire protection safe-shutdown

analysis. The tube side of these coolers is within the scope of license renewal for pressure

boundary integrity to ensure that a flowpath to the sample sink is maintained. These coolers

are not within scope for the int&nded function of heat exchange because the samples are taken

when the fluid is relatively cool (approximately 200 'F). The applicant further stated that it

should not have listed heat exchange in LRA Tables 2.3.3.24 and 3.3.2-24 as an intended

function for the sampling system heat exchanger tubes. Since the only intended function of the

sample cooler tubes is pressure boundary, fouling is not an AERM for license renewal.

The staff reviewed the applicant's response to RAI 3.3.2.1.24-1 and found the response to be

reasonable and acceptable because the applicant agreed that LRA Tables 2.3.3.24 and 3.3.2-

24 should not have listed heat exchange as an intended function for the sampling system heat

exchanger tubes, and that the only intended function of this component is pressure boundary.

On the basis of its review of the LRA and the additional information included in the applicant's

responses to the above RAls, the staff finds the aging effects of the sampling system

component types given above that are not addressed by the GALL Report are consistent with

industry experience for these material-environment combinations. 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

sampling system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff reviewed the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.3.2-24 of the LRA identifies the following AMPs for managing the aging effects

described above for the sampling system:

* Water Chemistry Control Program (Appendix B.3.2)

The applicant credited the Water Chemistry Control Program with managing the loss of material

aging effect on the stainless steel piping, flow elements, orifices, and valve bodies exposed to

treated water. During its review, the staff determined that it needed additional information,

requested in RAI 3.3-10. Section 3.3.2.3.0 of this SER describe RAI 3.3-10, the applicant's

response to this RAI, and the staff's evaluation of the response.

Section 3.0.3.2.1 of this SER provides the staff's detailed review of this AMP.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the sampling system component types that are not

addressed by the GALL Report. In addition, the staff finds the program descriptions in the

FSAR Supplement acceptable.

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Conclusion' " 'a

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 sampling system

components that are not addressed by the GALL Report, so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

3.3.3 Conclusion'

On the basis of its review, the staff concludes that the applicant has demonstrated that the

effects of aging for auxiliary systems will be adequately managed so that the'intended functions

will be maintained consistent with the'CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplerment program summaries and concludes

that they adequately describe the 'AMPs credited for managing aging of the auxiliary systems,'

as required by 10 CFR 54.21 (d). ' ' -'

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 components and component groups associated with the following

-systems:

* main steam

* feedwater -

* steam generator blowdown

* auxiliary feedwater

* auxiliary steam and condensate recovery

3.4.1 Summary of Technical Information in the Application

In Table 3.4.1, "Summary of the6Aging Management Evaluations for Steam and Power

Conversion Systems in Chapter Vill of NUREG-1801," the applicant provided a summary

comparison of its AMRs with the AMRs evaluated in the GALL Report for the steam and power

conversion systems components and component groups that are relied on for license renewal.

The applicant's AMRs incorporated applicable plant-specific and industry operating experience

to determine the AERMs. The plant-specific evaluation included reviews of condition reports

and discussions with appropriate site personnel to identify AERMs. The applicant's review of

industry operating experience included a review of the GALL Report and operating experience

issues identified since the issuance of the GALL Report in 2001.

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The applicant conducts its ongoing review of plant-specific and industry operating experience in

accordance with the FNP, Units 1 and 2, Operating Experience Program.

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the steam and power donversion system

components that are within the scope of license renewal and subject to an AMR will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by. 10 CFR 54.21 (a)(3).

The staff performed an audit and review to confirm the applicant's claim that certain identified

AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report. However, the staff did determine that the applicant presented

applicable material in the LRA and identified the appropriate GALL Report AMPs. Section 3.0.3

of this SER documents the staff's evaluations of these AMPs. The FNP Audit and Review

Report, summarized in Section 3.4.2.1 of this SER, documents the details of the staff's

evaluation of the audit and review for these AMRs.

The staff also performed an audit and review of those AMRs that were consistent with the GALL

Report and for which further evaluation is recommended. During the audit and review, the staff

determined that the applicant's further evaluations were consistent with the acceptance criteria

in Section 3.4.2.2 of the SRP-LR. The FNP Audit and Review Report, summarized in Section

3.4.2.2 of this SER, documents the details of the staff's evaluation of the audit and review for

these AMRs.

The staff conducted a technical review of the remaining AMRs that were not consistent with the

GALL Report. In the review, the staff evaluated whether the applicant identified all plausible

aging effects and listed the appropriate aging effects for the material-environment combinations

specified. Section 3.4.2.3 of this SER documents the details of the staff's review and

evaluation for these AMRs that are not consistent with the GALL Report.

Finally, the staff reviewed the AMP summary descriptions in the FSAR Supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

reactor system components.

Table 3.4-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in Section 3.4 of the LRA that are addressed in the GALL Report.

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11
Table 3.4-1 Staff Evaluation for Steam and Power Conversion System Components in the

., .. - . .ReportGAL

:Component Group X AgIn '&AM -Effec-c' -PifEGAL- ,' 'AMP-ii'R i SaAd EvaluaInto _________________H a M ech anlsm 's;.? *<R ep rto t Ad d __ __ __ __ _e

Piping and fittings In Cumulative fatigue TLAA, evaluated 10 CFR 5421(c)(1)(i) Consistent with

main feedwater line, i damage in accordance with analyses remain valid' GALL, which *

steamline, and ' 10 CFR 54.21 (c) recommends further

AFW piping (PWR , . evaluation. (See

only) Section 3.4.2.2.1)

Item Number

3.4.1-1

Piping and fittings, Loss of material Water chemistry Water Chemistry Consistent with

valve bodies and due to general and one-time Control Program GALL, which

bonnets, pump (carbon steel only), inspection (Appendix B.3.2); recommends further.

casings, tanks, -- '' - 'pitting, and crevice One-Time Inspection -evaluation. (See -

tubes, tubesheets, corrosion ' Program (Appendix Section 3.42.2.2)

channel head and B.5.5)

shell (except main'

steam system)

Item Number

3.4.1-2

AFW piping ' Loss of material Plant specific Service Water Consistent with _

Item Number due to general, ' - Program (Appendix - GALL; which

3.4.1-3 pitting, and crevice B.4.4) . recommends further

corrosion, MIC, and evaluation.: (See

biofouling Section 3.4.2.2.3)

Oil coolers In AFW -Loss of material - Plant specific - Water Chemistry - Consistent with --

system (lubricating ' due to general Control Program - GALL, which

oil side possibly' (carbon steel only), - ; (Appendix B.3.2); recommends further

contaminated with' pitting, and crevice One-Time Inspection evaluation.: (See

water) ' ' ' corrosion and MIC Program (Appendix. Section 3.4.2.2.5)

Item Number B.5.5)

3.4.1-4 * .

Extemal surface of Loss of material Plant specific External Surfaces Consistent with

carbon steel - due to general Monitoring Program GALL, which

components '' ' corrosion (Appendix B.5.3) recommends further

Item Number evaluation. (See

3A.1-5 ' Section 3.4.2.2.4)

Carbon steel piping Wall thinning due to FAC Flow-Accelerated Consistent with

and valve bodies - FAC Corrosion Program GALL, which

Item Number' (Appendix B.4.1)' recommends no

3.4.1-6 further evaluation.

' -(See Section

3.4.2.1)

Carbon steel piping Loss of material Water chemistry Water Chemistry Consistent with

and valve bodies in due to pitting and Control Program GALL, which'

main steam system crevice corrosionr (Appendix B.3.2)- recommends no

Item Number ' ' , further evaluation. r

3.4.1-7' - - ' ; . . ; . (See Section

_:_ '__ *__ __3.4.2.1) -

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Component Gro'up:* - ADiing ffc ei'AMP hInGALL %^ t -9^Ap i~ ~L''' iCs ~Sft luaI' '' -

Closure bolting in- Loss of material Bolting integrity External Surfaces Consistent with

high-pressure or due to general . Monitoring Program GALL, which

high-temperature corrosion; crack (Appendix B.5.3) recommends no

systems initiation and growth further evaluation.

Item Number due to cyclic - ' (See Section

3.4.1-8 loading and/or SCC 3.4.2.1)

Heat exchangers Loss of material OCCW system None Consistent with

and due to general GALL, which

coolers/condensers (carbon steel only), recommends no

serviced by OCCW pitting, and crevice further evaluation.

Item Number corrosion, MIC, and (See Section

3.4.1-9 biofouling; buildup 3.4.2.1)

of deposit due to

biofouling_

Heat exchangers Loss of material CCCW system None Consistent with

and due to general GALL, which

coolers/condensers (carbon steel only), recommends no

serviced by CCCW pitting, and crevice further evaluation.

Item Number corrosion (See Section

3.4.1-10 3.4.2.1)

External surface of Loss of material Aboveground - External Surfaces Consistent with

aboveground CST due to general carbon steel tanks Monitoring Program GALL, which

Item Number (carbon steel only), (Appendix B.5.3) recommends no

3.4.1-11 pitting and crevice further evaluation.

corrosion (See Section

. _ 3.4.2.1)

External surface of Loss of material Buried piping and None Consistent with

buried CST and due to general, tanks surveillance GALL, which

AFW piping pitting, and crevice recommends no

Item Number corrosion and MIC or further evaluation.'

3.4.1-12 (See Section

Buried piping and 3.4.2.1)

tanks inspection

Consistent with

GALL, which

recommends further

evaluation. (See

Section 3.4.2.2.5)

External surface of Loss of material Boric acid Borated Water Consistent with

carbon steel due to boric acid corrosion 'Leakage Assessmnent GALL, which

components corrosion and Evaluation recommends no

Item Number Program (Appendix further evaluation.

3.4.1-13 B.3.5) (See Section

._ _3.4.2.1)

The staff's review of the applicant's steam and power conversion system and associated

components followed one of several approaches. One approach, documented in Section

3.4.2.1, 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, involved the

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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, involved 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. Section 3.0.3 of this SER documents the staff's review of AMPs that are credited

to manage or monitor aging effects of the steam and power conversion system components.

3.4.2.1 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Not Recommended --

Summary of Technical Information in the Application

In Sections 3.4.2.1.1 through 3.4.2.1.5 of the LRA, the applicant identified the materials,

environments, and AERMs. The applicant identified the following programs that manage the

aging effects related to the steam and power conversion system components:

* Water Chemistry Control Programl. - -

* One-Time Inspection Program

* Flow-Accelerated Corrosion Program

* External Surfaces Monitoring Program

* -Borated Water Leakage Assessment and Evaluation Program

* Service Water Program

Staff Evaluation

In Tables 3.4.2-1 through 3.4.2-5 of the LRA, the applicant summarized the AMRs for the steam

and power conversion systems and identified which AMRs it considered to be consistent with

the GALL Report.

The staff conducted an audit and review of 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 GALL. Therefore, the staff finds that the applicant identified

applicable aging effects that are appropriate for the material-environment combinations listed.

On the basis of its audit and review, the staff concludes that the applicant has demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). - - -7 -

Conclusion -.

The staff has determined the applicant's claim of consistency with the GALL Report. The staff

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing associated aging effects. On the basis of its review, the staff finds

that the applicant has demonstrated that the effects of aging for these componentswilI be

adequately managed so that their-intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). -

_3-271
The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that they adequately describe the AMPs credited for managing aging in these components, as

required by 10 CFR 54.21 (d).

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

Is Recommended

Summary of Technical Information in the Application

In Section 3.4.2.2 of the LRA, the applicant 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, microbiologically

influenced corrosion, and biofouling

* 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 analysis to determine whether it adequately

addressed these issues. 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 FNP Audit and Review

Report documents the details of the staff's audit and review.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections.

3.4.2.2.1 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 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.

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

In Section 3.4.2.2.2 of the LRA, the applicant addressed programs to verify the effectiveness of

the Water Chemistry Control Program in managing the loss of material due to general, pitting,

and crevice corrosion.

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Section 3.4.2.2.2 of the SRP-LR recommends-further evaluation of programs to manage the

loss of material due to general, pitting, and crevice-corrosiori of carbon steel piping and fittings,

valve bodies and bonnets, pump casings, pump suction and discharge lines,-tanks, tubesheets,

channel heads, and shells (except for main steam system components), and the loss of

material due to crevice and pitting corrosion for stainless steel tanks and heat exchanger/cooler

tubes. The GALL'Report water chemistry program relies on monitoring and control of water

chemistry, based on the guidelines in EPRI TR-102134,"PWR Secondary Water Chemistry

Guideline," Revision 3, issued May 1993, for secondary water chemistry in PWRs, to manage

the effects of the loss of material due to general (carbon steel only), pitting, or crevice

corrosion. However, corrosion may occur at locations of stagnant flow conditions. Therefore,.

the GALL Report recommends that the effectiveness of the water chemistry control program

should be verified to ensure that corrosion is not occurring.

In addition to the components identified in the GALL Report, the applicant credited the Water

Chemistry Control Program (AMP B.3.2) for management of this aging effect and the One-Time

Inspection Program (AMP B.5.5) to verify the effectiveness of the Water Chemistry Control

Program;' 'The staff reviewed the'applicant's proposed programsa6nd plant operating

experience to ensure that corrosion is not 6ccurring and that the component's intended function

will be maintained during the period of extended operation. Sections 3.0.3.2.1 and 3.0.3.1,

respectively, of this SER document the staff's evaluation of these programs. The staff

concludes that thes'e programs are appropriate for managing this'aging effect.

On the basis of its review, the staff finds that ti'iapplicant appropriately evaluated AMR results

involving the management of the'loss'of material due to'general, pitting, and crevice corrosion,

for components in the steam and power conversion systems, 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 the effects of aging will be adequately

managed so that the'intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by,10'CFR 54.21(a)(3).

3.4.2.2.3 Loss of Material Due to General, Pitting, and Crevice Corrosion, Microbiologically

Influenced Corrosion, and Biofouling

In Section 3.4.2.2.3 of the LRA, the applicant stated that the carbon steel AFW piping that is

subject to general, pitting, and crevice corrosion,'MIC,'and biofouling is located in a crosstie to

the OCCW system, which contains raw water. -Two locked, closed valves separate this OCCW

system crosstie piping from the AFW system. The applicant credited the Service Water

'Program'(AMP B.4.4) to manage the'loss of material in this crosstie piping.

Section 3.4.2.2.3 of the SRP-LR recommrendsJfurther evaluation of programs to manage the

loss of material due to general, pitting, and'crevice' corrosion, MIC, and biofouling for carbon

steel piping and fittings for untreated water'from the backup water supply in the AFW system.

The staff determined that the FNP AFW system conitains treated water, so that the components

in this system are not subject to these same aging effects/mechanisms. In addition, for certain

sections of the AFW system piping that are exposed to a raw water environment, the Service

Water Program manages this aging effect. Based on its review, the staff concludes that the .c

Service Water Program is consistent with GALL AMP Xl.M20, "Open-Cycle Cooling Water

System," with acceptable ehhariceme'nts'and can effectively manage the'aging effects of loss of

4-3-273
material. Specifically, the applicant will enhance the scope of the Service Water Program to

include the inspection of piping from the main service water header to the air compressor and

the service water pump columns. Section 3.0.3.2.5 of this SER documents the staff's

evaluation.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving the management of the loss of material due to general, pitting, and crevice

corrosion, MIC, and biofouling for AFW system components since the FNP AFW system

contains treated water and is not exposed to a raw water environment, 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 the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2.4 General Corrosion

In Section 3.4.2.2.4 of the LRA, the applicant credited the External Surfaces Monitoring

Program (AMP B.5.3) with managing the loss of material on carbon steel component exterior

surfaces subject to 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 structures and components, including closure

bolting, exposed to operating temperature less than 212 OF. The GALL Report recommends

further evaluation to ensure adequate management of this aging effect.

In RAI 2.3.4.4-1, the staff questioned why the applicant excluded the turbine lube oil subsystem

and its components from the scope of license renewal. In its response dated April 7, 2004, the

applicant stated that it added several components related to the turbine lube oil subsystem to

the scope of the AFW system., The staff reviewed the components added to FNP LRA Table

3.4.2-4 as subject to an AMR and concludes that the addition of these components does not

result in the addition of material-environment combinations or AMPs for the AFW system.

The staff reviewed the applicant's proposed program to ensure that it will have an adequate

program in place for the management of this aging effect. Based on the staff's review of the

External Surfaces Monitoring Program, the staff concludes that the program will adequately

manage these aging effects. Section 3.0.3.3.2 documents the evaluation of this program.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving the management of the loss of material due to general corrosion for components in

the steam and power conversion systems, 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 the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

In Section 3.4.2.2.5 of the LRA, the applicant stated that loss of material due to general

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II
corrosion (carbon steel.only), pitting and crevice corrosion, and MIC could occur in stainless

steel and carbon steel components exposed to lubricating oil in the auxiliary system.

Section 3.4;.2.2.5 of the SRP-LR addresses th'e loss'of material due to general corrosion

(carbon steel only), pitting and crevice corrosion',;aid MIC which could occur in stainless steel

and carbon steel shells',tubes, and tubesh6ets Withinrthe bearing oil coolers (for steam'turbine

pumps) in the PWR AFW system. The GALLI Report recommends further evaluation to ensure

the adequate management of these aging effects.' -

Section 3.4.2.2.5 of the SRP-LR also addressesthe loss of material dueto general, pitting, and

crevice corrosion, and MIC, which could occur in underground piping and fittings and the

emergency CST in the AFW system and the underground CST in the condensate system. The

Buried Piping and Tank Inspection Program relies on industry practice, frequency of pipe

excavation, and operating experience to mana~ge the effects of the loss of material from

general, pitting, and crevice corrosion, and MIC. The SRP-LR recommends verification of the

effectiveness of the buried piping'and tank inspection program to'6valuate an applicant'sinspection frequency and operating'e'xperience" with buried cormponents, ensuring that loss of

material is not occurring.

In the LRA, the applicant determined that the loss of material 'is not an AERM for the AFW

system turbine lube oil cooling system. The applicant stated that water intrusion is nota

credible occurrence since the system is closed. A review'of the operating experience does not

indicate any significant water intrusion. Treated water'supplied from the CST'cools the lube oil.

The applicant credited the Water Chermistry Control Program (AMP B.3.2) and the One-Time

Inspection Program (AMP B.5.5) with managing aging of the lube oil heat exchanger

components, such that the integrity of the lube'6il 'system will be maintained. - -

The staff reviewed the applicant's proposed program to ensure that it will have an adequate -

program in place for the management of this aging effect. Based on the staff's review of the

Water Chemistry Control Program and the One-Time Inspection Program, the staff concludes

that the programs will adequately manage these aging effects. Sections 3.0.3.2.1 and 3.0.3.1,

respectively, of this SER document the eValuation~of the programs.

In the LRA, the applicant stated that the CST and AFW system piping are not buried. -

Therefore, the applicant determined thlat thes6 c6mponents are not subject to the aging effect,

of loss of material in underground piping, fittings, and storage tanks.

The staff confirmed that the CST and AFW dystem'piping alrebnot buried at FNP and concurs:

with the applicant that these co6mnponents are not'subject to the aging effect.

On the basis of its review, the staff finds'that the'applicant appropriately evaluated AMR results

involving the managementof the loss of material'due to general, pitting, and crevice corrosion,

and MIC for components in the steam and power conversion systems, 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 the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by'10 CFR 54.21 (a)(3).

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Conclusion

On the basis of its audit and review, the staff finds that the applicant's further evaluations,

conducted in accordance with;the GALL Report, are consistent with the acceptance criteria in

Section 3.4.2.2 of the SRP-LR. Since the applicant's AMR results are otherwise consistent with

the GALL report, the staff finds that the applicant has demonstrated that the effects' of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

current licensing basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3 AMR Results That Are Not Consistent With or Not Addressed in the GALL Report

3.4.2.3.1 Main Steam System AMR Results

Summary of Technical Information in the Application

In Section 3.4.2.1.1 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 system:

* Water Chemistry Control Program

* One-Time Inspection Program

* Flow-Accelerated Corrosion Program

* External Surfaces Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.4.2-1 of the LRA, the applicant summarized the AMRs for the main steam system

components and identified which AMRs it did not consider to be consistent with the GALL

Report.

Staff Evaluation

The staff reviewed the AMRs of the main steam system components relating to those

combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.4.2-1. Section 3.4.2.1 of this SER documents the staff's evaluation.

The technical staff reviewed the AMRs of the combinations of main steam system components,

materials, environments, and AERMs that are not addressed in the GALL Report. These

combinations use notes F through J in LRA Table 3.4.2-1. For the combinations using notes F

through J, the staff determined that the applicant has identified all applicable AERMs and has

credited the appropriate AMPs for managing these effects. The staff also reviewed the

applicable FSAR Supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects

Table 2.3.4-1 of the LRA lists individual system components for the main steam system 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 flow orifice/element, piping, steam traps, turbine drive pump

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casings, and valve bodies. . 2

For these component types, the applicant identified the following materials, environments, and

AERM s ^' " '' '' - '' -'- ' ' '' '': - ' - ' - . .

+; ' ' - , ,. ', , ,: i, ,, , . ' , . 4 . - .

* Stainless steel components exposed to-steam and treated water environments are -

subject to the aging effects'of cracking and loss of material.

* Carbon steel components'exposed to an air/gas environment are subject to the aging-

'effect of loss of material. ' '' .; -. I _;*,., -*., R. ' , -h

* Alloy steel components exposed to steam and treated water environments are subject to

the aging effect of loss of material. !''r 2* -.

* ' Stainle'ss ste l components exposed to inside and outside environments experience no

aging effects. ' * 8

* Alloy st66l domponents'exposed to an outside environment experience no aging effects.

During its review, the staff determined that'it needed additional information to complete its,-

evaluation 'of the main steam syst6m. Sectiori 3.4.2.3.6.1 of the SER provides the staff's

evaluation of the loss of 'material for stainless steel components in a treated water environment

and cracking for stainless`steel components in a treated water and steam environment. Section

3.2.2.3.4.2 of the'SER provides' the staff's evaluation of the loss of preload and cracking for,

closuire bolting. -

Table 3.4.2-1 of the LRA identifies the loss of material as an aging effect for alloy steel

steam/fluid traps in a steam and treated water environment. The applicant credited the Water

Chemistry Control Program to manage this aging effect. However, the applicant did not credit a

one-time inspection to verify the effectiveness of the Water Chemistry Control Program. In RAI

3.4-3 dated March 17, 2004,' the staff asked the applicant to justify not performing a one-time - inspection to verify the effectiveness of the Water Chemistry Control Program for the -

steam/fluid traps. In its response dated March 5, 2004, the applicant stated that a one-time

inspection is not necessary for the main steam components because the very low oxygen

concentration and the ultra-high purity of the steam exiting the SGs precludes significant

corrosion of the carbon steel and alloy steel components in this system. While the steam traps

will be exposed to treated water as well as steam, the condensed steam does not contain

sufficient oxygen or contaminates'to promote significant corrosion of alloy steel components.

However, the staff does not concur withthe applicant's assessment that corrosion is not an

AERM for the alloys steel traps in condensate. Although NUREG-1 801 does not recommend a

one-time inspection to verify the effectiveness of the Water Chemistry Control Program for main

steam components in a steam environment, the traps are located in a moist steam and treated

water environment where general corrosion is a likely aging effect. Therefore, a one-time

inspection is recommended to verify the effectiveness of the Water Chemistry Control Program

in this 6nvironment. Inr its supplemental response to RAI 3.4-3 dated May 28, 2004, the

applicant stated that it will include alloy ste'el steam and fluid traps in steam and treated water

environments within the scope of the One-Time'Inspection Program.: The staff considers the

applicant's use of the one-time inspection acceptable since it verifies the effectiveness of the

Water Chemistry Control Program to manage the loss of material for the steam and fluid traps

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in condensed steam and treated water environments.

Table 3.4.2-1 of the LRA identifies no aging effects for alloy steel steam/fluid traps in an outside

environment. The LRA defines an outside environment as a environment where components.

are exposed to direct sunlight, precipitation, and freezing conditions. 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 212 OF; such corrosion may be due to air, moisture, or humidity. In RAI 3.0-1 (B) dated

March 17, 2004, the staff asked. the applicant to provide a program to manage corrosion on the

external surface of alloy steel steam/fluid traps in an outside environment, or to justify not

managing this aging effect. In its response dated April 16, 2004, the applicant stated that the

steam/fluid traps are exposed to operating temperatures greater than 212 OF. These

steam/fluid traps are located in a vented portion of the main steam valve room (MSVR), which

is covered with a roof, but the walls are made from grating. Components in the MSVR are

exposed to outside air but are sheltered from rain.. The applicant also identified that borated

water leakage is not a concern in this area. Based on the applicant's response that the

steam/fluid traps operate at a temperature above 212 OF and are sheltered from rain, the staff

considers the loss of material on the external surface of these components not to be an AERM.

On the basis of its review of the LRA, the staff finds that the aging effects of the main steam

system component types given above that are not addressed by the GALL Report are

consistent with industry experience for these material-environment combinations. The staff did

not identify any omitted aging effects for the combinations in LRA Table 3.4.2-1, using notes F

through J. Therefore, the staff finds that the applicant has identified the appropriate aging

effects for the materials and environments associated with the above components in the main

steam system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.4.2-1 of the LRA identifies the following AMPs for managing the aging effects described

above for the main steam system:

* Water Chemistry Control Program (LRA Section B.3.2)

* One-Time Inspection Program (LRA Section B.5.5)

Sections 3.0.3.2.1 and 3.0.3.1 of this SER, respectively, provide the staff's review of these

AMPs.

On the basis of its review of the LRA, the staff finds that the applicant has identified the,-,

appropriate AMPs for managing the aging effects of the main steam system component types

that are not addressed by the GALL Report. In addition, the staff finds the program

descriptions in the FSAR Supplement acceptable.-

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Conclusion

On the basis of its review, the'staff concludes thatthe applicant has adequately identified the;

aging effects,' and the AMPs credited for managing the aging effects, for the main steam

system components that are not addressed by the'GALL Report, so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the'AMPs credited with managing aging in

these components, as required by 10 CFR 54.21(d).

3.4.2.3.2 Fee'dwater System''AMR Results :'--

Summary of Technical Information in the AnODlication

In Section 3.4.2.1.2 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs to manage the aging effects related to

the feedwater system:

* Water Chemistry Control Program

* -One-Time Inspection Program

* Flow-Accelerated Cor'r6sion' Program:

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.4.2-2 of the LRA,; the applicant provided a summary of AMRs for the feedwater

system components and identified which AMRs it considered not to be consistent with the GALL

Report.

Staff Evaluation

The staff reviewed the AMRs of the feedwater system components relating to those

combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.4.2-2. Section 34.22.1 of this'SER documents the staff's evaluation. :-

The technical staff reviewed the AMR of the combinations of feedwater system components,

materials, environments, and AERMs that are not addressed in the GALL Report. These

'combinations use 'notes F through'J in LRA Table 3.4.2-2. For the combinations using notes F

through J, the staff determined that the applicant has identified all applicable AERMs and has

credited appropriate AMPs for managing these effects. The staff also reviewed the applicable

FSAR Supplements for the AMP'tio ensure that they adequately describe the AMPs.

During the scoping review, in its response to RAI 2.1-1 dated June 4,2004, the applicant added

pump casing to Tables 2.3.4.2 and 3.4.2-2. The applicant stated that the aging effect for the

stainless'steel 'pump ca-ings in a treated water environment is loss of material. ;The One-Time

lnspecti6n Program and the Wate-r Chemistry Control Program will manage this aging effect.

The applicant'did not identify any aging'effects for the'stAinless steel pump casings in an inside

environment.

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Aging Effects

Table 2.3.4-2 of the LRA lists individual system components for the feedwater system 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 piping and valve bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Stainless steel components exposed to treated water environment are subject to the

aging effects of cracking and loss of material.

* Stainless steel components exposed to an outside environment experience no aging

effects.

* Stainless steel components exposed to an inside environment experience no aging

effects.

During its review, the staff determined that it needed additional information to complete its

evaluation of the feedwater system. Section 3.4.2.3.6.1 outlines the staff's evaluation of the

loss of material for stainless steel components in a treated water environment and cracking for

stainless steel components in a treated water and steam environment. Section 3.2.2.3.4.2

provides the staff's evaluation of the loss of preload and cracking for closure bolting.

On the basis of its review of the LRA, the staff finds that the aging effects given for the

feedwater system component types listed above are appropriate for the industry experience for

these material-environment combinations. The staff did not identify any omitted aging effects

for the combinations in LRA Table 3.4.2-2 using notes F through J. Therefore, the staff finds

that the applicant has identified the appropriate aging effects for the materials and

environments associated with the above components in the feedwater system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.4.2-2 of the LRA identifies the following AMP for managing the aging effects described

above for the feedwater system:

* Water Chemistry Control Program (LRA Section B.3.2)

Section 3.0.3.2.1 of this SER provides the staff's review of. this AMP.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the feedwater system component types that are not

addressed by the GALL Report. In addition, the staff finds the program descriptions in the

FSAR Supplement acceptable.

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Conclusion . i i,!''-, : - - . :-

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 feedwater system -

components that are not addressed by the GALL R6port, -so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 51.21 (a)(3). -.-

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately desbribes the'AMPs credited for-managing aging in.

these components, as required by 10'CFR 54.21(d)' --- -

3.4.2.3.3 'Steam Generator Blowdown System AMR Review

Summary of Technical Information in the ADplication

In Section 3.4.2.1.3 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 SG blowdown system: .- - -

* 'Water Chemistry Control Program

* One-Time Inspection Program -;

* Flow-Accelerated Corrosion Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.4.2-3 of the LRA, the applicant provided a summary of AMRs for the SG blowdown

-system components and identified which AMRs it considered not to be consistent with the GALL

Report.'

Staff Evaluation

The staff reviewed the AMRs of the contairirmrnt spray system components relating to those

combinations of components, materials, environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.4.2-3. Section 3.4.2.1 of this SER documents the'staff's evaluation.-

The technical staff reviewed the AMR of the combinations of SG blowdown system

components, materials, environments, and AERMs that are not addressed in the GALL Report.

These-combinations use'notes F through J in LRA-Table 3.4.2-3. For the combinations using

notes'F through J,'the staff concluded that the ap plicant has identified all applicable AERMs

and has credited appropriate AMPs'for ma~naging these effects. .The staff also reviewed the

applicable FSAR Supplements for the AMPs to ensure that the program descriptions -

adequately describe the AMPs.

Aging Effects

Table 2.3.4-3 of the LRA lists individual system' components for the SG blowdown system within

the- scope of license -renewal and subject than AMR. The component types that do not rely on

the GALL Report for an AMR include valve bodies.;-l

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For this component type, the applicant identified the following materials, environments, and

AERMs:

* Stainless steel components exposed to a treated water environment are subject to the

aging effects of cracking and loss of material. -

* Stainless steel components exposed to an inside environment experience no aging

effects.

During its review, the staff determined that it needed additional information to complete its

evaluation of the SG blowdown system. Section 3.4.2.3.6.1 of the SER provides the staff's

evaluation of the loss of material for stainless steel components in a treated water environment

and cracking for stainless steel components in a treated water and steam environment. Section

3.2.2.3.4.2 of the SER outlines the staff's evaluation of the loss of preload and cracking for

closure bolting.

On the basis of its review of the LRA, the staff finds the aging effects of the above SG

blowdown system component types that are not addressed by the GALL Report are consistent

with industry experience for these material-environment combinations. The staff did not identify

any omitted aging effects for the combinations in LRA Table 3.4.2-3 using notes F through J.

Therefore, the staff finds that the applicant has identified the appropriate aging effects for the

materials and environments associated with the above components in the.SG blowdown

system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.4.2-3 of the LRA identifies the following AMP for managing the aging effects described

above for the SG blowdown system:

* Water Chemistry Control Program (LRA Section B.3.2)

Section 3.0.3.2.1 of this SER provides the staff's review of the AMP.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the SG blowdown system component types that are not

addressed by the GALL Report. In-addition, the staff finds the program descriptions in the

FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the SG blowdown.

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,

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- - -

10 CFR 51.21(a)(3). '

The staff also reviewed the applicable FSAR'Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the6AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.4.2.3.4 Auxiliary Feedwater System AMR Review

Sumnrnarv of Technical Information in the AMplication

In Section 3.4.2.1.4 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 AFW system:

* . Water Chemistry Control Program

* : One-Time Inspection Program ''

* ' 'External Surfaces Monitoring Program ^ - ' -.

* Service Water Program

In Table 3.4.2-4 of the LRA, the applicant summarized the AMRs for the AFW system

components'and identified which AMRs it did not conisider to be consistent with the GALL

Report.

Staff Evaluation ' . i --

The staff reviewed the AMRs of the Auxiliary Feedwater system components relating to those

combinations of components, materials,'environments, and AERMs and found them to be

consistent with the GALL Report. These combinations use notes A through E in LRA Table

3.4.2-4. Section 3.4.2.1 of this SER documents the staff's evaluation.

The technical staff reviewed the AMR of the combinations of AFW system components,

materials, environments, and AERMs that are not addressed in the GALL Report. These

combinations' u'se notes F through J in LRA Table 3.4.2-4. For the combinations using notes F

through J, the staff determined that the applicant has identified all applicable AERMs and has

credited appropriate AMPs for managing these effects. The staff also reviewed the applicable

FSAR Supplements for the AMPs to ensure that they adequately describe the AMPs.

During the scoping review, in response to RAI 2.3.4.4-1 dated April 7, 2004, the applicant

identified the turbine AFW pump turbine lube oil subsystem component types subject to aging

management as closure bolting, filters, flow orifice/element, oil cooler (shell, channel head,

tubesheet, and tubes), piping, pump &asings,!sight glasses, tanks (auxiliary oil reservoir), and''

valve bodies. Of these' components,-the' LRA did not identify the flow orifice/element, sight

glasses,: and tanks'(auxiliary oil reservoir); however, the applicant has added them to.Tables*-

2.3.4.4 and 3.4.2-4. The applicant stated that no aging effects require aging 'management for

the stainless steel flow orifice/element, the glass sight glasses, and the carbon tanks (auxiliary

oil reservoir) in a lube oil environment, or for the stainless steel flow orifice/element and the

glass'sight glasses'in an inside environment hf -' l ;

During the scoping review, in its response to RAI 2.3.3.7-4 dated April 22, 2004, the applicant

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added CST diaphragms to Tables 2.3.4.4 and 3.4.2-4. The applicant stated that the Periodic

Surveillance and Preventive Maintenance Activity will manage the aging effects for the

elastomer diaphragm resulting from a change in, material properties, cracking, and loss of

material in treated water and air/gas environments.

During the scoping review, in response to NRC Inspection Report Nos. 50-348/2004-007 and

50-364/2007-007, dated June 22, 2004, the applicant added the vents for the condensate

storage tank in the scope of license renewal. The vents are considered an integral subpart of

the tank and, consequently, are part of the condensate storage tank listed in LRA Table 3.4.2-

4. The applicant stated that the aging effect for the carbon vents in an air/gas (non-wetted)

environment is loss of material. The applicant stated that this aging effect will be managed by

the One-Time Inspection Program.

Aging Effects

Table 2.3.4-4 of the LRA lists individual system components for the AFW system within the

scope of license renewal and subject to AMR. The component types that do not rely on the

GALL Report for AMR include filters; flow orifice/elements; oil cooler shell, channel head,

tubesheet, and tubes; piping; pump casings; and valve bodies.

For these component types, the applicant identified the following materials, environments, and

AERMs:

* Stainless steel components exposed to a treated water environment are subject to the

aging effects of loss of material and fouling.

* Stainless steel oil cooler tubes exposed to a lube oil environment are subject to the

aging effect of fouling.

* Stainless steel components exposed to inside and outside environments experience no

aging effects.

* Carbon steel, stainless steel, and glass components exposed to a lube environment

experience no aging effects.

* Elastomers exposed to treated water and air/gas environments experience a change in

material properties, cracking, and loss of material.

* Glass components exposed to an inside environment experience no aging effects.

During its review, the staff determined that it needed additional information to complete its

evaluation of-the AFW system. Section 3.4.2.3.6.1 of the SER outlines the staff's evaluation of

the loss of material for stainless steel components in a treated water environment. Section

3.2.2.3.4.2 of the SER provides the staff's evaluation of the loss of preload and cracking for

closure bolting.

Table 3.4.1-4 of the LRA states that the applicant determined loss of material not to be an

AERM for the AFW system turbine oil cooling system. Table 3.4.2-4 identifies no AERMs for

carbon and stainless AFW components in an oil environment. For AFW oil cooler tubes, Table

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3.4.2-4 only identifies fouling as an AERM. The GALL Report recommends a plant-specific

AMP for the loss of material due to general (carbon steel only), pitting, and crevice corrosion

and MIC in carbon and stainless steel components exposed to lubricating oil that may be

contaminated with water. In RAI 3.4-5, the staff asked the applicarit to justify not managing the

aging effect of loss of material due to general, 'pitting, and crevice corrosion and MIC for the

AFW system turbine oil cooling system components.; In its response dated April 7, 2004, the

applicant stated that the lubricating oil systems are typically closed systems, and tube failure is

not assumed because the cooling water side of the tubes is managed for aging. Therefore, the

lubricating oil is assumed to be free of water contamination. Significant corrosion is only

expected where water can settle or pool. Since water contamination is not expected, settling or

pooling should not occur; therefore, the lubricating oil systems are not susceptible to the loss of

material due to general, pitting, and crevice corrosion or MIC. The applicant stated that its

operating experience supports this conclusion; Although not credited for aging management,

operators visually check the oil levels for the high safety injection/charging pumps during every

shift for the proper level and for visual evidence of contamination: The oil is sampled every.3,

months and is changed based on the results of the sample analysis. The applicant also checks

oil levels and conditions during quarterly pump surveillance testing. Based on the applicant's

response that it does not expect water settlinig or pooling and because operating experience at

FNP supports this conclusion, the staff concurs that the loss of material in the lubricating oil:

coolers is not an AERM.

Table 3.4.2-4 of the LRA identifies foulinig as an aging effect for the AFW oil cooler tubes in

both an 'oil and treated water environment and the oil cooler tubesheet in a treated water

environment. The applicant credited the One-Time Inspection Program to manage this aging

effect. In RAI '3.4-6, the staff requested the applicant to explain why Section B.5.5.5, "Specific

Components in the Sample Population," of the One-Time Inspection Program does not contain

inspection criteria for the AFW tubes or tubesheet. In its response dated March 5, 2004, the

applicant stated that the oil cooler in Table'3.4.2-4 is the turbine-driven auxiliary feedwater

pump (TDAFWP) turbine lube oil cooler,--and the LRA identifies fouling as the aging effect for,

the stainless 'steel cooler tubes, tubesheet, 'and channel head in a treated water environment.

Further evaluation indicated that fouling is not a plausible aging mechanism for stainless steel

in a treated water environment. The AFW oil cooler draws its cooling water from the AFW

supply to the pump, which is the same treated water that is stored in the CST. The rigorous

chemistry controls maintained on this system eliminate fouling as a plausible aging effect.

Therefore, the applicant stated that it will remove fouling as an AERM for stainless steel AFW

cooler components- in'the treated water environment:' :Fouling of the oil cooler tubes in a lube oil

environr6ent remains as an aging effect maniaged by-the One-Time Inspection Program. To

address the staff's concern that Section B.5.5.5 of the One-Time Inspection Program does not

include the lube oil cooler tubes, SNC will include a one-time inspection of the TDAFWP turbine

lube oil coolers within the listing of one-time inspections on the FNP License Renewal Future

Actions Commitment List. Based on the applicant's response, the staff concurs that fouling for

the stainless steel AFW 'co6ler components in a treated water environment is not an aging

effect that requires management, and SNC's inclusion-of the one-time inspection of the

TDAFWP turbine lube oil coolers on the FNP Ucense Renewal Future Actions Commitment List

is an acceptable action 'to d6cument this'inspection.

By RAI 3.4-7, the staff requested the applicant to'explain how degradation will be managed on

the bottom exterior surface of the buried condensate storage tank (CST). In its response dated

March 5, 2004, the applicant stated that the One-Time Inspection Program will be revised to

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include a thickness measurement of the bottom of the Unit 1 CST prior to the period of

extended operation.

On the basis of its review of the LRA, the staff finds that the aging effects of the above AFW

system component types that are not addressed by the GALL Report are consistent with..

industry experience for these material-environment combinations. -The staff did not identify any

omitted aging effects for the combinations in LRA Table 3.4.2-4 using notes F through J.

Therefore, the staff finds that the applicant has identified the appropriate aging effects for the

materials and environments associated with the above components in the AFW system.

Aging Management Programs

After evaluating the aging effects identified by the applicant for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR 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 AFW system:

* Water Chemistry Control Program (LRA Section B.3.2)

* One-Time Inspection Program (LRA Section B.5.5)

* Periodic Surveillance and Preventive Maintenance Activities (LRA Section B.5.9)

Sections 3.0.3.2.1, 3.0.3.1, and 3.0.3.3.4 of this SER, respectively, provide the staff's review of

these AMPs.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the AFW system component types that are not

addressed by the GALL Report. In addition, the staff finds the program descriptions in the

FSAR Supplement acceptable.

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and the AMPs credited for managing the aging effects, for the 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 51.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program descriptions and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.4.2.3.5 Auxiliary Steam and Condensate Recovery System AMR Review

Summary of Technical Information in the Application

In Section 3.4.2.1.5 of the LRA, the applicant identified the materials, environments, and

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AERMs. The applicant identified the following programs that manage the aging effects related

to the auxiliary steam and condensate recovery system: .. ~~~~ . .......... ,;

* ' ' Water Chemistry Control Programr ' ; , ,) 

Flow-Accelerated Corrosion Program ...... * One-Time Inspection Program

* External Surfaces Monitoring Program'

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.4.2-5 of the-LRA,'the applicant provided a summary of AMRs for the auxiliary stearfi'

and coidensate recovery system components-arid identified which AMRs'it considered not to

be consistent with th6 GALL Report. ' .-.

Staff Evaluation..

The staff reviewed the AMRs of the Auxiliary Steam and Condensate Recovery System

components relating to those combinations of components, materials, environments, and

AERMs and found them to be consistent with the GALL Report. These combinations use notes

A through E in LRA Table'3.4.2-5. Section`,3.4.2.1 -of this SER 'documIe'nts the' staff's

evaluation. - ..

The technical staff reviewed the AMR of the combinations of auxiliary steam and'cnde~n'sate

recovery systemrcomponents, materials, environments, and AERMs that are not addressed in

the GALL Report. These combinations use'notes F through J iriLRA Table 3.4.2-5.' For thecombinations using notes F through J, the staff determined that the applicant has identified all

applicable AERMs and has credited appropriate AMPs for managing these effects. The staff

also reviewed the applicable FSAR Supplements for the AMPs to ensure that they adequately

describe the AMPs. -

Aging Effects . ' , , -

Table 2.3.4-5 of the LRA lists individual system components for the auxiliary steam and'

condensate recovery system within the scope of license renewal and subject to an AMR. The

com'ponenit types that do not rely on the GALL Report for AMR include piping, pump casings,

and tanks. - ' ' -

For these component types, the applicant identified the following materials, environments, and'

AERMs:'

* Stainless steel components exposed to steam and treated water environments are

subject to the aging effects of cracking and loss of material.

* 'Cast'iron and carbon steel components exposed to a treated water environment are

subject to the aging eff ect of loss of rnaterial. ' -

* Cast iron components exposed to an inside environmr ent are subject to the aging effect:

of loss of material.

* Stainless steel components exposed to an inside environment experience no aging

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effects.

During its review, the staff determined that it needed additional information to complete its

evaluation of the auxiliary steam and condensate recovery system. Section 3.4.2.3.6.1 outlines

the staff's evaluation of the loss of material for stainless steel components in a treated water

environment and cracking for stainless steel components in a treated water and steam

environment. Section 3.2.2.3.4.2 provides the staff's evaluation of loss of preload and cracking

for closure bolting.

In RAI 3.4-7, the staff requested the applicant to explain how it will manage loss of material on

the exterior bottom surface of the CST which is not accessible for visual inspection. In its

response dated March 5, 2004, the applicant stated that it will revise the One-Time Inspection'

Program to include a thickness measurement of the bottom of the Unit 1 CST before the period

of extended operation. The exterior bottom surfaces of the auxiliary steam condensate tanks

and condensate return unit tanks are accessible for visual inspection. Based on the applicant's

response, the staff finds the one-time inspection of the CST bottom acceptable to manage this

aging effect.

On the basis of its review of the LRA, the staff finds the aging effects of the above auxiliary

steam and condensate recovery system component types that are not addressed by the GALL

Report are consistent with industry experience for these material-environment combinations.

The staff did not identify any omitted aging effects for the combinations in LRA Table 3.4.2-5

using notes F through J. Therefore, the staff finds that the applicant has identified the

appropriate aging effects for the materials and environments associated with the above

components in the auxiliary steam and condensate recovery system.

Aging Management Programs

After evaluating the applicant's identification of aging effects for each of the above components,

the staff evaluated the AMPs to determine if they are appropriate for managing the identified

aging effects. The staff also determined that the FSAR Supplement adequately describes the

program.

Table 3.4.2-5 of the LRA identifies the following AMPs for managing the aging effects described

above for the auxiliary steam and condensate recovery system:

* Water Chemistry Control Program (LRA Section B.3.2),

* Borated Water Leakage Assessment and Evaluation Program (LRA Section B.3.5)

Sections 3.0.3.2.1 and 3.0.3.1 of this SER, respectively, provide the staff's review of these

AMPs.

On the basis of its review of the LRA, the staff finds that the applicant has identified appropriate

AMPs for managing the aging effects of the auxiliary ste~anand condensate recovery system

component types that are not addressed by the GALL Report. In addition, the staff finds the

program descriptions in the FSAR Supplement acceptable.

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11
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 auxiliary steam

and condensate recovery system components that are not addressed by the GALL Report, so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 51.21(a)(3).' "..--

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.4.2.3.6 Generic Issues for the Steam and Power Conversion Systems

3.4.2.3.6.1 Table 3.4.2 of the LRA identifies loss of material as the aging effect for stainless

steel components in treated water environments and cracking as the aging effect for stainless

steel components in steam or treated water environments. The applicant credited the Water

Chemistry Control Program with managing these aging effects. In RAI 3.4-1, the staff

requested that the applicant explain why it will not perform a one-time inspection to verify the

effectiveness of the Water Chemistry Control Program for these aging effects. In its response

dateid April 7, 2004,_the applicant stated that the Water Chemistry Control Program provides for

the control of chemistry parameters associated with the corrosion of stainless steel components

in the steam and power conversion systems. Chlorides, sulfides, and dissolved oxygen

concentrations are maintained in the low range of parts per billion, and, under these conditions,

the corrosionqof austenitic stainless steels is unlikely.- The FNP operating experience review,

performed for development of the FNP license renewal application did not identify any failures

of stainless steel components in the steam and power conversion system caused by cracking or

loss 'of material. 'This site-specific operating experience confirms that the Water Chemistry

Control Program is adequate to manage this aging effect without a one-time inspection. Based

on the applicant's response that the Water Chemistry Program effectively manages the loss of

' material and cracking for stainless steel piping in the steam and power conversion systems,

and because operating experience at FNP supports this conclusion, the staff concurs that an

inspection program is not required.

3.4.3 Conclusion - : .- . ; i . . 1 ., -,..;..

On the basis of its review, the staff concludes that the applicant has demonstrated that the

aging effects associated with the steam and power. conversion system components will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, astrequired by 10 CFR 54.21 (a)(3).

The staff also reviewed the'applicable FSAR Supplement program summaries and concludesthat the FSAR Supplement adequately'describes the AMPs credited for managing aging in..

steam and power conversion system components,,as required by-10 CFR 54.21(d).

- --. I 1_'.. -_

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3.5 Aging Management of Containments, Structures, and Component Supports

This section of the SER documents the staff's review of the applicant's AMR results for the

containments, structures, and component supports, as well as component groups associated

with the following systems:

* pressurized-water reactor concrete containment

* auxiliary building

* diesel generator building

* turbine building

* utility/piping tunnels

* water control structures

* steel tank structures

* yard structures

* component supports

3.5.1 Summary of Technical Information in the Application

In Table 3.5.1 of the LRA, "Summary of Aging Management Evaluations for Structures and

Component Supports in Chapters II and IlIl of NUREG-1801," the applicant provided a summary

comparison of its AMRs with the AMRs evaluated in the GALL Report for the containments,

structures, and component supports component groups that it relies on for license renewal.

The applicant's AMRs incorporated applicable operating experience in determining AERMs.

These reviews included evaluation of plant-specific and industry operating experience. -The

plant-specific evaluation included reviews of condition reports and discussions with appropriate

site personnel to identify AERMs. The applicant's review of industry operating experience

included a review of the GALL Report and operating experience issues identified since the

issuance of the GALL Report in 2001.

The applicant's ongoing review of plant-specific and industry operating experience is conducted

in accordance with the FNP, Units 1 and 2, Operating Experience Program.

3.5.2 Staff Evaluation

The staff reviewed LRA Section 3.5 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging on the containments, structures, and component

supports that are within the scope of license renewal and subject to an AMR will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff performed an audit and review to confirm the applicant's claim that certain identified

AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report. However, the staff did determine that the material presented in

the LRA was applicable and that the applicant had identified the appropriate GALL Report

AMPs. The staff documents its evaluations of the AMPs in Section 3.0.3 of this SER. The FNP

Audit and Review Report, summarized in Section 3.5.2.1 of this SER, documents details of the

staff's evaluation of the FNP audit and review for these AMRs.

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The staff also performed an audit and review of those AMRs that were consistent with the GALL

Report and for which further evaluation is recommended. During the audit and review, the staff

determined that the applicant's further evaluations were consistent with the acceptance criteria

in Section 3.5.2.2 of the SRP-LR. The FNP Audit and Review Report, summarized in Section

3.5.2.2 of this SER, details the staff's evaluation of the FNP audit and review for these AMRs.

The staff conducted a technical review of the remaining AMRs that were not consistent with the

GALL Report. The review included evaluating whether the applicant had identified all plausible

aging effects that were appropriate for the material-environment combinations specified.

Section 3.5.2.3 of this SER'documents the details of the staff's review and evaluation for these

AMRs that are not'consistent with the GALL Report.

Finally, the staff reviewed the AMP summaries in the FSAR Supplement to ensure that the

applicant adequately described the programs credited with managing or monitoring aging for

the reactor system components.

Table 3.5-1 below summarizes the staff's evaluation of components; aging effects/mechanisms,

and AMPs listed in Section 3.5 of the LRA that are addressed in the GALL Report.

Table 3.5-1 Staff Evaluation for Containments, Structures, and Component Supports System

Components in the GALL Report

rhOmpnerit^ Gr68i, gEffeVG; AUPlnGA 'aluation

Ic@-X< §~ {-1.|' I--- Mechani sml | e Z | * * * Mr..; | i

Common Components of All Types of PWR and BWR Containment

Penetration Cumulative fatigue TLAA evaluated in 10 CFR 54.21 (c)(11)(i)i Consistent with

sleeves, bellows, damage (CLB accordance with analyses remain valid GALL, which

and dissimilar metal fatigue analysis 10 CFR 54.21 (c) recommends further

welds exists) evaluation. (See -

Item Number 'Section 3.5.2.2.6)

3.5.1-1

Penetration Cracking due to Containment ISI None Consistent with

sleeves, bellows, cyclic loading, or and containment GALL, which

and dissimilar metal crack initiation and leak rate test recommends further

welds. growth due to SCC . evaluation:- (See -

Item Number - ' ,-. . . Section 3.5.2.2.7)

3.5.1-2

Penetration Loss of material Containment ISI Inservice Inspection Consistent with

sleeves, bellows, due to corrosion and containment Program (Appendix GALL, which

and dissimilar metal leak rate test. B.3.1) recommends no

welds ' - further 'valuation.

Item Number (See Section'

3.5.1-3 3.5.2.1)

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Compbnent Group'' 'AgingEffec i-3 AMP fInGALI-,Z S M In LRA.- i Staff EvildatidiAi,

- .s - .. 6 -..-...-..--. ' -:- 

Personnel airlock Loss of material Containment ISI Inservice Inspection Consistent with

and equipment due to corrosion 'and containment Program (Appendix .GALL, which

hatch leak rate test B.3.1) recommends no

Item Number further evaluation.

3.5.14 (See Section

-_ - _ 3.5.2.1)

Personnel airlock Loss of leak' Containment leak Inservice Inspection Consistent with

and equipment tightness in closed rate test and plant Program (Appendix GALL, which

hatch position due to TSs B.3.1) recommends no

Item Number mechanical wear of further evaluation.

3.5.1-5 locks, hinges, and (See Section

cl6sure 3.5.2.1)

mechanisms

Seals, gaskets, and Loss of sealant and Containment ISI Inservice Inspection Consistent with

moisture barriers leakage through and containment Program (Appendix GALL, which

Item Number containment due to leak rate test B.3.1); Structural- recommends no

3.5.1-6 deterioration of joint Monitoring Program further evaluation.

seals, gaskets, and (Appendix B.4.3) (See Section

moisture barriers . 3.5.2.1)

PWR Concrete (Reinforced and Prestressed) and Steel Containment

BWR Concrete (Mark II and Ill) and Steel (Mark l, II, and ill) Containment

Concrete elements: - Aging of accessible Containment ISI Inservice Inspection Consistent with

foundation, dome, and inaccessible Program (Appendix GALL, which'

and wall concrete areas due B.3.1) recommends further

Item Number to leaching of evaluation. (See

3.5.1-7 calcium hydroxide, Section 3.5.2.2.1)

aggressive

chemical attack,

and corrosion of

embedded steel

Concrete elements: Cracks, distortion, Structures None Consistent with

foundation and increases in monitoring GALL, which

Item Number component stress recommends no

3.5.1-8 level due to further evaluation.

settlement (See Section

. .,3.5.2.2.2) __ 

Concrete elements: Reduction in Structures None Consistent with

foundation foundation strength monitoring GALL, which

Item Number due to erosion of recommends no

3.5.1-9 porous concrete further evaluation.

subfoundation (See Section

3.5.2.2.2)

Concrete elements: Reduction of Plant specific Structural Monitoring Consistent with

foundation, dome, strength and Program (Appendix GALL, which

and wall - modulus due to B.4.3) recommends further

Item Number elevated evaluation. (See

3.5.1-10 temperature Section 3.5.2.2.3)

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'Componient'Grop .'gn Effe `C", ;.iAMPKlGALL" ~:~- -a AMP ,- ILR , -. StfEvaluto

Prestressed Loss of prestress TL evaluated in 10 CFR 54.21(c)(1)(i) Consistent with

containment: due to relaxation, accordance with analyses remain valid GALL, which -

tendons and shrinkage, creep, 10 CFR 54.21(c) recommends further

anchorage and elevated evaluation. (See

components temperature Section 3.5.2.2.5)

Item Number

3.5.1-11

Steel elements: Loss of material Containment ISI Inservice Inspection Consistent with

liner plate, due to corrosion in and cointaininent Program(Appendix - - -GALL; which

containment shell accessible and leak rate test B.3.1); Borated recommends further

Item Number inaccessible areas : Water Leakage evaluation. (See

3.5.1-12 Assessment and Section 3.52.2.4)

Evaluation Program -

:__ _(Appendix B.3.5)

Steel elements: Loss of material Protective coating Inservice Inspection Consistent with

protected by coating due to corrosion in monitoring and Program (Appendix GALL, which

Item Number accessible areas - maintenance' B.3.1) recommends no

3.5.1-14 only .'further evaluation. - . (See Section -

3.5.2.1)

Prestressed Loss of material Containment ISI 'Inservice Inspection Consistent with

containment: due to corrosion of Program (Appendix GALL, which

tendons and prestressing -- B.3.1) - - recommends no -

anchorage tendons and' further evaluation.

components anchorage (See Section

Item Number components 3.5.2.1)

3.5.1-15

Concrete elements: Scaling, cracking, Containment ISI None Consistent with

foundation, dome, and spalling due to GALL, which

and wall freeze-thaw; recommends no

Item Number expansion and : further evaluation.

3.5.1-16 . cracking due to (See Section

reaction with 3.5.2.1)

aggregate

Class I Structures -

All groups except All types of aging Structures Structural Monitoring Consistent with

Group 6: accessible effects monitoring Program (Appendix GALL, which

interior/exterior B.4.3) recommends no

concrete and steel further evaluation.

components - (See Section

Item Number . 3.5.2.2) -

3.5.1-20 - -

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ComponentGrouipj 1:-'Agl -Eff AI.VIMPInGA LL,.' *'AMP I LR&)e t I;--

.__';__-____'__ '. .Mechan, :, h 2 I eX; tX. 

Groups 1-3, 5, and Aging of Plant specific Structural Monitoring Consistent with

7-9: inaccessible inaccessible Program (Appendix GALL, which

concrete concrete areas due B.4.3) recommends further

components, such to aggressive evaluation. (See

as exterior walls chemical attack and Section 3.5.2.2)

belowgrade and corrosion of

foundation embedded steel

Item Number

3.5.1-21

Group 6: all All types of aging Inspection of Service Water Pond Consistent with

accessible/ effects, including water-control Dam Inspection' GALL, which'

inaccessible loss of material due structures or Program (Appendix recommends no

concrete, steel, and to abrasion, - FERC/US Army B.3.3); Structural further evaluation.

earthen cavitation, and Corps of Monitoring Program (See Section

components corrosion, Engineers dam- (Appendix B.4.3) 3.5.2.2)

Item Number inspection and

3.5.1-22 maintenance

Group 5: liners Crack initiation and Water chemistry Water Chemistry Consistent with

Item Number growth due to SCC; and monitoring of Control Program GALL, which

3.5.1-23 loss of material due spent fuel pool (Appendix 8.3.2) recommends no

to crevice corrosion water level further evaluation.

(See Section

3.5.2.1)

Groups 1-3, 5, and Cracking due to Masonry wall Structural Monitoring Consistent with

6: all masonry block restraint, shrinkage, Program (Appendix GALL, which

walls creep, and B.4.3) recommends no

Item Number aggressive further evaluation.

3.5.1-24 environment (See Section

3.5.2.1)

Groups 1-3, 5,and Cracks, distortion, Structures None Consistent with

7-9: foundation and increases in monitoring GALL, which

Item Number component stress recommends no

3.5.1-25 level due to further evaluation.

settlement (See Section

3.5.2.2.2)

Groups 1-3 and 5-9: Reduction in- Structures None Consistent with

foundation foundation strength monitoring GALL, which

Item Number due to erosion of recommends no

3.5.1-26 porous concrete further evaluation.

subfoundation (See Section,

3.5.2.2.2)

Groups 1-5: Reduction of Plant specific None Consistent with

concrete strength and GALL, which:

Item Number modulus due to recommends further

3.5.1-27 elevated evaluation. (See

temperature Section 3.5.2.2.3)

Component Supports

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Component Group i Ag ng Effe ~-; - C M P ri iGALL. -- 'AP#iRA ' Staff Evalu.at.ion

Groups 7 and 8: Crack initiation and Plant'specific K None Consistent with

liners growth due to SCC; GALL, which

Item Number loss of material due recommends no'

3.5.1-28 to crevice corrosion . further evaluation.

(See Section

3.5.2.1)

All groups' support Aging component Sructures Structural Monitoring Consistent with

members: anchor supports monitoring Program (Appendix GALL, which -

bolts, concrete B.4.3) recommends no

surrounding anchor further evaluation.'-

bolts, welds, grout (See Section

pads, bolted 3.5.2.1)

connections, etc. '

Item Number

3.5.1-29

Groups B.1, B1.2, Cumulative fatigue TLAA evaluated in 10 CFR 54.21(c)(1)(i) Consistent with

and B1.3 support damage (CLB accordance with analyses remain valid GALL, which

members: anchor fatigue analysis 10 CFR 5421(c) recommends further

bolts and welds exists) evaluation. (See

Item Number -. Section 3.5.2.2.11)

3.5.1-30 .'

All groups' support Loss of material Boric acid Borated Water Consistent with

members: anchor due to boric acid corrosion Leakage Assessment GALL, which

bolts and welds corrosion and Evaluation recommends no

Item Number Program (Appendix B further evaluation.

3.5.1-31 3.5) . (See Section

'__ .3.5.2.1)

Groups B1.1, B1.2, Loss of material . -- Structural Monitoring Consistent with

and 61.3 support due to Program (Appendix - GALL, which

members: anchor environmental B.4.3); Inservice recommends no

bolts, welds, spring corrosion! loss of . Inspection Program further evaluation.'

hangers, guides, mechanical function . - (Appendix B.3.1) (See Section

stops, and vibration due to corrosion, 3.5.2.1)

isolators . distortion, dirt, 3

Item Number overload, etc. . - : : -

3.5.1 -32 '"

Group 61.1: high- Crack initiation and Bolting Integrity None Consistent with'

strength, low-alloy., growth due to SOC :: i ' GALL, which

bolts . e . recommends no

Item Number further evaluation.

3.5.1-33 - .: ;- ". " (See Section , ____ __ __ .__ .3.5.2.1)

The staff's review of the applicant's containments, structures, and components supports and -

associated components followed one of several approaches. One approach, documented in

Section 3.5.2.1 of this SER, involved the staff's review of the AMR results for components in the

containments, structures, and components supports and associated components 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,-involved the staff's review of the

AMR results for components in the containments,structures, and components supports and

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associated components that the applicant indicated are consistent with the GALL Report, and

for which further evaluation is recommended. A third approach, documented in Section 3.5.2.3

of this SER, involved the staff's review of the AMR results for components in the containments,

structures, and components supports and associated components 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

containments, structures, and components supports in Section 3.0.3 of this SER.

3.5.2.1 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Not Recommended

Summary of Technical Information

In Sections 3.5.2.1.1 through 3.5.2.1.5 of the LRA, the applicant identified the materials,

environments, and AERMs. The applicant identified the following programs that manage the

aging effects related to the containments, structures, and component support system:

* Structural Monitoring Program

* Water Chemistry Control Program

* Fire Protection Program

* Borated Water Leakage Assessment and Evaluation Program

* Service Water Pond Dam Inspection

* Inservice Inspection Program

Staff Evaluation

In Tables 3.5.2-1 through 3.5.2-9 of the LRA, the applicant summarized the AMRs for the

containments, structures, and components support systems and identified which AMRs it

considered to be consistent with the GALL Report by referencing line items in Table 3.5.1-1.

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 applicable aging effects that are

appropriate for the material-environment combinations specified. --

3.5.2.1.1 Structures and Components Supports, PWR Concrete Containments (Table 3.5.2-1)

For the containment's internal structure steel liner components, the applicant, in Table 3.5.2-1

of the LRA, credited the Borated Water Leakage Assessment and Evaluation Program to

manage the aging effects of loss of material. The applicant also referenced Item 3.5.1-20 from

Table 3.5.1 of the LRA, which states that the Structural Monitoring Program will be credited with

managing structural steel. However, Table 3.5.2-1 of the LRA does not identify this program.-

This aging effect does'not require further evaluation, provided that components in all groups.

except Group 6'are within the scope of the Structural Monitoring Program.' In a telephone

co'nference on Jan'uary 22, 2004, the staff requested the' applicant to clarify whether the

Structural Monitoring Prograrm is credited for structural steel. The applicant confirmed during

the telephone conference that Table 3.5.2-1 of the LRA should have included the Structural

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Monitorinh Program. The applicant further'stated that the omission of the Structural Monitoring

Program in Table 3.5.2-1 of the LRA was an editorial error, and agreed to provide an

application errata to make the correction.:

By letter dated May 28, 2004, the applicant provided its application errata to correct this editorial

error. In its errata, the applicant stated that for the carbon steel component type "internal

structure-steel liners" in an inside environment, the Strnuctural Monitoring Program should be

added to the'AMP column for managing loss'of -material. The 'staff finds th'e applicant's

response acceptable.

The staff reviewed the Structural Monitoring Program (AMP B.4.3) and determined that the

applicant had included the structural steel component group within the scope of the program.

The staff documents its evaluation in Section 3.0.3.2.4 of this SER. On the basis of its review,

the staff concludes that this line item is acceptable.

On the basis of its audit and review, the staff determined that for AMRs not requiring further;-

evaluation, as identified in Table 3.5.1 of the LRA (Table 1), the applicant's references to the

GALL Report are acceptable and no further staff review is required.

On this basis, 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).

Conclusion

The staff determined the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing associated aging effects. On the basis of its' review, the staff finds

that the applicant has demonstrated that the effdcts'of aging for these components will be

adequately managed so that their intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Staff Review Pertaining to Recent Oberatina Experience and Emerginq Issues

Because the GALL Report and SRP-LR were issued in July 2001, these documents do not

reflect the most current recommendations formanaginrg 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 proposed to address these items for license

renewal. The following are the applicant's responses to these RAls, and the staff's evaluation

of the responses.

The staff reviewed Tables 3.5.1 and 3.5.2, as well as additional evaluations provided in Section

3.5.2.2 of the LRA, "Further Evaluation of Aging Management as Recommended by.

NUREG-1 801 for Structures and Component Supports." The only emerging issue applicable to

the AMR of FNP structures and components supports pertains to NRC ISG-3. The applicant

indicated in plant-specific notes 53 and 54 of Table 3.5-2 (page 3.5-67) of the LRA'that both the

leaching of calcium hydroxide and the corrosion of embedded steel are considered applicable

aging mechanisms for FNP based on NRC ISG-3 provisions. Because' the applicant has fully

adopted the NRC ISG-3 position, the staff finds the applicant's handling of the issue

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acceptable. The above staff review also, indicated that some additional information and

clarifications were required related to (1) further evaluations recommended in NUREG-1801,

and (2) the plant-specific operating experience. The staff transmitted additional RAls to obtain

this information. The staff evaluates the applicant's responses to these RAls in Section 3.5.2.3

of this SER.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing associated aging effects.

On the basis of its review, the staff finds that the applicant has demonstrated that the effects of

aging for these components will be adequately managed so that their intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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

Is Recommended

Summary of Technical Information in the Apnlication

In Section 3.5.2.2 of the LRA, the applicant provided further evaluation of aging management

as recommended by the GALL Report for structures and components support systems. The

applicant provided information concerning how it will manage the following aging effects:

* aging of inaccessible concrete areas

* 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 Structural Monitoring Program

* reduction of strength and modulus of concrete structures due to elevated temperature

* loss of material due to corrosion in inaccessible areas of the steel containment shell or

liner plate

* loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

* cumulative fatigue damage

* cracking due to cyclic loading and SCC

* aging of structures not covered by the Structural Monitoring Program

* aging management of inaccessible areas

* aging of supports not covered by the Structural Monitoring Program

* cumulative fatigue damage

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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 determined whether the applicant had adequately addressed the issues:.-

that required further evaluation.- In addition,'the staff audited these additional evaluations -

against the criteria-contained in Section 3.5.2.2 of the SRP-LR. The FNP Audit and Review

Report documents details of the staff's FNP audit and review.

The GALL Report indicates that further evaluation should be performed for the aging effects

described in the following sections of this SER.

I. Containment

The staff reviewed Section 3.5.2.2 of the LRA against the criteria in Section 3.5.2.2.1 of the

SRP-LR, which addresses several areas discussed below.

3.5.2.2.1 Aging of Inaccessible Concrete Areas

In Section 3.5.2.2.1 of the LRA, the applicant addressed aging of inaccessible concrete areas

of 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 XL.S2, UASME Section Xl, Subsection IWL," for

managing the aging of the accessible portions of the containment structures. The applicant

credited the Inservice Inspection Program (AMP B.3.1), which the staff reviewed and concludes

is acceptable.. The staff documents its evaluation in Section 3.0.3.1 of this SER. Subsection

IWL exempts those portions of the concrete containment that are inaccessible (e.g., foundation,

belowgrade exterior walls, or concrete covered by a liner) from examination.

The applicant also credited the Structural Monitoring Program (AMP B.4.3) where accessible

areas are monitored for evidence of aging effects that may be applicable to containment

structures. Section 3.0.3.2.4 of this SER evaluates this program; which is consistent with GALL

AMP XI.S6, "Structural Monitoring Program." The Structural Monitoring Program will be

enhanced to monitor structures and structural components which are within the scope of license

renewal, but are not currently monitored by the program. Specifically, the program will be

enhanced to include the belowgrade concrete of in-scope structures that are currently not

monitored and can only be examined when they are exposed by excavation.

The GALL Report, Volume 2, Chapter II, Table Al (as modified by ISG-3), recommends further

evaluation'to'manage the aging effects for containiment 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 resulting from these five aging mechanisms are cracking, change in material

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properties, and loss of material.

Freeze-Thaw

Section 3.5.2.2.1.1 of the SRP-LR does not address freeze-thaw as an aging mechanism for

concrete containments because the GALL Report does not recommend further evaluation.

However, ISG-3 clarifies the staff's 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.

The applicant stated that FNP is located in a region subject to moderate weathering conditions.

In the LRA, the applicant noted that FNP is close to the region of negligible weathering

conditions and is not exposed to saturated water conditions. The applicant also stated that

FNP concrete structures are designed in accordance with American Concrete Institute (ACI)

specification ACI-318-63, "Building Code Requirements for Reinforced Concrete," and

constructed in accordance with ACI-301-66, 'Specifications for Structural Concrete for

Buildings," and ASTM standards. The following requirements result in dense concrete of good

quality and low permeability with resistance to aggressive chemical solutions:

* high cement content

* low water-to-cement ratio

* proper curing

* -- adequate air entrainment

The staff reviewed relevant operating experience to confirm that loss of material from freezethaw has not been observed, either through the Inservice Inspection Program or the Structural

Monitoring Program.

On the basis that any concrete that satisfies the requirements of AUl 318-63 will meet the

guidelines of ISG-3, as well as on the results of an audit of operating experience under the

Inservice Inspection Program and the Structural Monitoring Program, the staff concludes that

loss of material and cracking resulting from freeze-thaw will be adequately managed by the

Inservice Inspection Program.

Leaching of Calcium Hydroxide

Section 3.5.2.2.1.1 of the SRP-LR states that cracking, spalling, and increases in porosity and

permeability caused by leaching of calcium hydroxide could occur in inaccessible areas of PWR

concrete and steel containments. The GALL Report, as updated by ISG-3, recommends further

evaluation of plant-specific programs to manage the aging effects for inaccessible areas, if

specific criteria cannot be satisfied.

The GALL Report states that leaching of calcium hydroxide becomes significant only if the..

concrete is exposed.to flowing water. Even if reinforced concrete is exposed to flowing water,

such leaching is not significant if the concrete is constructed to ensure that it is dense, well

cured, and has low permeability, and that cracking is well controlled.

In the LRA, the applicant stated that FNP concrete structures are designed in accordance with

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ACI 318-63.

On the basis that ACI 318-63 provides assurance that the applicant has met the criteria of the

GALL Report and ISG-3, and that leaching of calcium hydroxide is not significant at FNP, the

staff concludes that the Inservice Inspection Program is sufficient for rmanagement of increases

in pof6sity aand permeability from this aging mechanism. This aging effect does not require a

plant-specific-AMP. ng e d no eu -a 

Aggressive Chemical Attack

Section 3.5.2.2.1.1 of the SRP-LR states that cirakirig, spalling, and increases in porosity and

permeability c&aused by aggressive chemical attack could occur in inaccessible areas of PWR

concrete and steel containments.' The GALL Report recommends further evaluation of

plant-specific programs to "manage'the agin ffecsf6 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 parts per million (pprn), or

sulfates are greater than 1500'ppm. ISG-3 'al`o6 states that a plant-specif ic program must

examine representative samples of belowg'rade concrete when excavated for any reason.,

The applicant stated that FNP is neither located in areas expIosed to sulfate or' chloride attack, '

nor is it located near industrial plants with emissions capable of changing environmental

parameters and causing degradation to concrete.''The staff confirmed from water chemical'

analysis results'that the site ground water isin6t agg'ressive. Table 2.4.7 of the FSAR present

these historical results. Results frorm'sample'testing performed in 2003 show that pH valu'es

are between 6.68 and 7.14, chlorid6 values between'2.00 and 3.74 ppm, and sulfate values'

between 5.25 and 6.37 ppm. 'In addition, to manage the aging effects for inaccessible areas,

the applicant uses the Structural Monitoring Program to examine belowgrade concrete when it

is exposed during excavation. ; - . . -- ; , --- . , -- , . -- .

The staff reviewed the information provided in the LRA and the guidelines provided in the SRPLR, the GALL Report, and ISG-3. The staff concludes that increases in porosity and -

permeability, loss of material (spalling, scaling) and cracking resulting from aggressive chemical

attack are'not significant for' concrete in inaccessible areas. The staff concludes that a- plantspecific program for examination of belowgrade concrete is-not required.

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 th6 GALL Report does not recommend furtherevaluation. However, ISG-3 clarified thestaff's position that further evaluation is appropriate if

investigations, tests, or examinations defnornstratethat the aggregates are reactive. :

In the LRA, the applicant stated that concrete structures are designed in accordance with ACI

318-63. Nonreactive aggregates were used at FNP. Aggregates were subjected to

petrographic testing'in accordance with ASTM C-295-65 and 0-89-66 to show that the

agg'egate is nnireactive. On the basis of its rbview,-the staff concludes that the 'petrographiic

test results show that the aggregates used for concrete containment at FNP'are not reactive,

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and therefore further evaluation is not required to address this aging effect.

Corrosion of Embedded Steel

Section 3.5.2.2.1.1 of the SRP-LR states that the loss of material caused by 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, and loss of material (spalling, scaling) caused by corrosion of

embedded steel, the GALL Report states that a plant-specific program is only required if the

belowgrade environment is aggressive. A plant-specific program is required in ISG-3 to

examine representative samples of belowgrade concrete when excavated for any reason.

In the LRA, the applicant stated that water chemical analysis results show that the site ground

water is not aggressive. Table 2.4.7 of the FSAR presents these historical results. Results

from sample testing performed in 2003 show pH values between 6.68 and 7.14, chloride values

between 2.00 and 3.74 ppm, and sulfate values between 5.25 and 6.37 ppm. In addition, the

applicant used the Structural Monitoring Program to examine belowgrade concrete when it is

exposed by excavation. For corrosion of embedded steel in accessible area, the applicant

manages aging using the IWL ISI- for containment.

The staff reviewed Section 3.5.2.2.1 of the LRA and determined that the site ground water

environment is not aggressive; subsequent sampling has shown that results have remained

within the limits identified in the GALL Report. The staff concludes that, in accordance with the

criteria in the GALL Report, this aging effect is not significant and is adequately managed

because the aggregates are not reactive and the ground water environment is not aggressive.

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 those AMR results

involving management of aging of inaccessible concrete areas for containment, as

recommended in the GALL Report and ISG-3.

The staff determines 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).

On the basis of its review, the staff concludes that the applicant appropriately evaluated those

AMR results involving management of aging of inaccessible concrete areas for containment, as

recommended in the GALL Report. Because the applicant's AMR results are otherwise,:

consistent with the GALL. Report, the staff finds that the applicant has demonstrated that- the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5.2.2.2 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 Structural Monitoring Program

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In Section 3.5.2.2.2 of the LRA, the applicant addressed (1) cracking, distortion, and increases

in component stress level due to settlement, and (2) reduction of foundation strength due to the

erosion of porous concrete subfoundations in the containment. The applicant credited the

Structural Monitoring Program (AMP B.4.3) to manage this aging effect. The staff evaluated

this program, which is consistent with GALL AMP XI.S6, "Structures Monitoring Program."

Section 3.0.3.2.4 of this SER documents the staff's evaluation.

Section 3.5.2.2.1.2 of the SRP-LR states that cracking, distortion, and increase in component

stress level resulting from settlement could occur in PWR concrete and steel containments.

Reduction of foundation strength due to erosion of porous concrete subfoundations could'also.

occur in all types of PWR containments. Some plants may rely on a dewatering system to

lower the site's ground water level. If the plant's CLB credits a dewatering system, the GALL

Report recommends verification of the continued functionality of this system during the period

of extended operation. The GALL Report does not recommend further evaluation, if this activity

is included in the scope of the applicant's Structural Monitoring Program.

The staff found that there are a number of nuclear reactor structures which have porous

concrete foundations with high alumina cement.- .These foundations are susceptible to -

reduction in strength and settlement potential due to erosion of cement from porous concrete. .

FNP Units 1 and 2 are not among those plants.

In the LRA, the applicant stated that FNP does not rely on a dewatering system for control of

settlement. The FNP containment foundation is constructed directly on bedrock (Lisbon

formation) and is not subject to settlement.- The applicant stated in Section 2B.7.3.1 of the

FSAR that it has not detected any indication of settlement from the monitoring of settlement of

structures. Ground water was not aggressive during plant construction and no changes in

ground water conditions have been observed. Finally, the applicant included these' components

within the-plant-specific Structural Monitoring Program, which will confirm that these aging

effects are adequately managed. In this case, the GALL Report does not recommend further

evaluation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated those

AMR results involving management of cracking, distortion, and increase in component stress

level due to settlement for containment components, as recommended in the GALL Report.

Because the applicant's AMR results are otherwise consistent with the GALL Report, the staff

finds that the applicant has demonstrated that the effects of aging will be adequately managed

so that the intended functions will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).'

3.5.2.2.3 Reduction of Strength and Modulus of Concrete Structures Due to Elevated

Temperature - -

In Section 3.5.2.2.3 of the LRA, the applicant addressed reduction of strength and modulus of

concrete structures resulting from elevated temperatures in containments.

Section 3.5.2.2.1.3 of the SRP-LR states that reduction of strength and modulus of elasticity'

due to elevated temperatures could occur in PWR concrete and steel containments. The GALL

Report calls for a plant-specific AMP and recommends further evaluation if any portion of the

concrete containment components exceeds specified temperature limits (i.e., general area

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temperature 66 0C (150 OF) and local area temperature 93 'C (200 0F).

In the LRA, the applicant stated that during normal plant operation, solar heat load and

equipment heat loads contribute to an increase in temperature'of the internal environment of

the concrete structures. Surface scaling and cracking may result from long-term exposure to

high temperatures. The applicant credited the Structural Monitoring Program (AMP B.4.3), to

manage this aging effect. The staff reviewed this program, which is consistent with GALL

AMP XL.S6, "Structures Monitoring Program"; Section 3.0.3.2.4 of this SER documents the

staff's evaluation. In addition, the applicant has enhanced this program to monitor aging effects

attributable to elevated temperatures.

The ACI Standard 318 provides a maximum temperature limit of 150 0F for liquid, gas, or vapor

in embedded piping in structural concrete. Section III, Division 2, of the ASME Code and

Appendix A of ACI-349-95, "Code Requirernent for Nuclear Safety-Related ConcreteStructures," provide limits at which exposure to high temperatures could impair the concrete.

Section III, Division 2, Subsection CC, of the ASME Code indicates that aging due to elevated

temperature exposure is not significant as long as concrete temperatures do not exceed 150

OF, except for local areas surrounding penetrations which may have increased temperatures up

to 200 OF. According to ACI-349, local area temperatures may reach 200 0F before special

provisions are required. Higher temperatures than specified may be allowed in the concrete, if

tests and/or calculations are completed to evaluate the reduction in strength which is then

applied to the design allowable limit.

In 1997, the applicant proposed an increase in the allowable RV concrete support temperature

from 130 'F to 190 OF. The staff raised a concern about exceeding the 150 0F limit.

Recognizing the potential degradation of the reactor pressure vessel supports subjected to

sustained temperatures higher than 150 'F, the applicant committed to inspect the structural

components, including portions of the reactor pressure vessel supports in the containment

building, as part of the Structural Monitoring Program. This program will ensure that significant

cracking of reactor pressure vessel supports that could affect the structural support of the RV or

cause out-of-plumb conditions will be detected and corrected. Even though FNP concrete

structures and components are not exposed to temperatures which exceed the threshold for

degradation, the applicant stated that it will continue to manage the concrete because of

possible isolated occurrences. Therefore, change in material properties due to elevated

temperature has been recognized as an aging effect requiring management at FNP for

concrete structures and components inside the containment only.' The applicant has enhanced

the Structural Monitoring Program to include inspection requirements for containment internal

concrete and for monitoring aging effects due to elevated temperature.

The staff reviewed the LRA and FSAR and determined that (1) the applicant has identified

areas where localized temperature could exceed 150 OF and has committed to an AMP, (2) in

most areas, containment bulk average temperature is below the ACI normal operation

temperature for general areas (i.e., 150 0F), and (3) the applicant has enhanced the Structural

Monitoring Program to include inspection requirements for containment concrete where the

temperatures could exceed specified limits. On this basis, the staff concludes that the applicant

has implemented adequate procedures for managing containment concrete degradation

induced by elevated temperature.

On the basis of its review, the staff finds that the applicant has appropriately evaluated those

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AMR results involving management of the reduction of strength.and modulus of concrete

structures due to elevated temperature for containment components, as recommended in the

GALL Report. Because the applicant's AMR results are otherwise consistent with the GALL

Report, the staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3): -- -

3.5.2.2.4 Loss of Material Due to Corrosion in Inaccessible Areas of Steel Containment Shell or

Liner Plate

In Section 3.5.2.2.4 of the LRA, the applicant addressed the aging effect of loss of material

resulting from corrosion in inaccessible areas of the containment liner plate.

Section 3.5.2.2.1.4 of the SRP-LR states that loss of material resulting from 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-specificprograms to manage this aging effect for inaccessible areas, if specific criteria defined in the

GALL Report cannot be satisfied, including (1) concrete meeting the requirements of ACI-318 -

or ACI-349 and the guidance of ACI-201.2R was used for the containment concrete in contact.

with the embedded containment shell or liner, (2) the accessible concrete is monitored to

ensure that it is free of penetrating cracks that provide a path for water seepage to the surface

of the containment shell or liner, (3) the accessible portion of the moisture barrier, at the

junction where the shell or liner becomes embedded, is subject to aging management activities

in accordance with IWE requirements, and (4) borated water spills and water ponding on the

containment concrete floor are not common, and when detected, are cleaned up in a timely

manner. - - -

In the LRA, the applicant stated that corrosion of inaccessible areas (embedded containment

liner) is not significant because concrete meeting the requirements of ACI-31 B or ACI-349 and

the guidance of ACI-201 .2R-77, "Guide to Durable Concrete," was used for those portions of

the containment structure in contact with the embedded containment liner. The applicant

monitors the concrete under the Structural Monitoring Program and the Inservice Inspection

Program to ensure that it is free of penetrating cracks. The applicant monitors the moisture -

barrier under the Inservice Inspection Program for aging degradation. Borated water leakage in

the containment structure is not a common occurrence and is monitored under the Borated

Water Leakage Assessment and Evaluation Program.

The staff reviewed the plant's operating experience and confirmed that there is no significant

corrosion in the accessible areas of the containment shell or liner plate. The staff noted that (1)

the applicant's inspection did not find significant corrosion in the accessible portion of the

containment liner plate, (2) the-applicant credited its IWE Inservice Inspection Program for

managing loss of material for-the accessible portion of the containment liner plate, and (3) if

significant corrosion of the accessible portions of the liner plate is observed, the applicant will

inspect the inaccessible portions of the containment liner plate. -

On the basis of its review, the staff finds that the applicant has appropriately evaluated those

AMR results involving the management of loss of material resulting from corrosion in

inaccessible 'areas of the steel containment shell or liner plate for containment components, as

recommended in the GALL Report. Because the applicant's AMR results are otherwise

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consistent with the GALL Report, the staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation; as required by

10 CFR 54.21 (a)(3).

3.5.2.2.5 Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature

As stated in the SRP-LR, loss of prestress due to relaxation, shrinkage, creep, and elevated

temperature is a TLAA, as defined in 10 CFR 54.3, and TLAAs must be evaluated in

accordance with 10 CFR 54.21 (c)(1). The staff documents its review of the applicant's

evaluation of this TLAA in Section 4.3.4 of this SER. In performing this review, the staff

followed the guidance in Section 4.5 of the SRP-LR.

3.5.2.2.6 Cumulative Fatigue Damage

As stated in the SRP-LR, cumulative fatigue damage is a TLAA, as defined in 10 CFR 54.3,

and TLAAs must be evaluated in accordance with 10 CFR 54.21 (c)(1).. The staff documents its

review of the applicant's evaluation' of this TLAA in Sectioni-4.3 of this SER. In performing this

review, the staff followed the guidance in Section 4.3 of the SRP-LR.

3.5.2.2.7 Cracking Due to Cyclic Loading and SCC

In Section 3.5.2.2.7 of the LRA, the applicant addressed the aging effects of cracking due to

cyclic loading and SCC.

Section 3.5.2.2.7 of the SRP-LR states that cracking of containment penetrations (including.

penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic loading or

SCC could occur in containments. The staff recommends further evaluation of inspection

methods to detect cracking due to cyclic loading and SCC because visual examinations (VT-3)

may be unable to detect this aging effect.

The GALL AMP XI.S1, UASME Section Xl Subsection IWE," 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 identifies examination categories

E-B and E-F as optional during the current term of operation. To address this issue for the

period of extended operation, examination categories E-B and E-F,' as well as additional

appropriate examinations to detect SCC in bellows assemblies and dissimilar metal welds, are

warranted.

The applicant stated that penetration sleeves and bellows are considered part of the ASME

Section Xl, Subsection IWE pressure boundary, and both the ASME Section Xl, Subsection

IWE, and the 10 CFR Part 50, Appendix J portions of the Inservice Inspection Program inspect

these component types.' The applicant credited the Inservice Inspection Program (AMP B.3.1)

to manage cracking for this component/commodity group. The staff reviewed this program and

documents its evaluation in Section 3.0.3.1 of this SER.

The applicant stated that SCC is not an applicable aging mechanism for carbon steel, from

which the penetration sleeves are made. The'applicant did not identify any dissimilar metal

welds that require aging management under this grouping. For stainless steel, SCC requires

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both high temperature and exposure to an aggressive environment, and the bellows are not

exposed to an aggressive environment. The applicant stated that it has not experienced SCC

in these components.

The staff finds that because SCC is not an effect requiring aging management for carbon steel

components, no dissimilar metal welds are subject to aging management, and the only

stainless'steel bellows is sheltered from aggressive' environments, the absence of additional

inspection'methods is acceptable. - -

On the basis of its review, the'staff finds that the applicant has appropriately evaluated those

AMR results involving management of cracking due to cyclic loading and SCC for containment

components, as 'recommended in the' GALL Report. Because the applicant's AMR results are,

otherwise consistent with the GALL Report, the staff finds that the applicant has demonstrated

that the effects of aging 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).

11. Class 1 Structures

The staff reviewed Section 3.5.2.2.2 of the LRA against the criteria in Section 3.5.2.2.2 of the

SRP-LR, which addresses several areas discussed below.

3.5.2.2.8 Aging of Structures Not Covered by'Structural Monitoring Program

In Section 3.5.2.2.8 of the LRA, the applicant addressed aging of Class 1 structures not.

managed by the Structural Monitoring Program.-

Section 3.5.2.2.8 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 Structural Monitoring

Program. This includes (1) scaling, cracking, and spalling due to repeated freeze-thaw for

Groups 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 Groups

1-5 and 7-9 structures, (3) expansion and cracking due to reaction with aggregates for Groups

1-5 and 7-9 structures, (4) cracking, spalling, loss of bond, and loss of material due to

corrosion of embedded steel for Groups 1-"5and 7-9 structures, (5) cracks, distortion, and -

increase in component stress level due to settlement for Groups 1-3, 5, and 7-9 structures, (6)

reduction'of foundation strength due to erosion of porous concrete subfoundation for.Groups

1-3 and 5-9 structures, (7) loss of material due to corrosion of structural steel components for

Groups 1-5, 7, and 8 structures, (8) loss of strength and modulus of concrete structures due to

elevated temperatures for Groups 1-5 structures, and (9) crack initiation and growth due to

SCC and loss of material due to crevice corrosion of stainless steel liner for Groups 7 and 8.

structures. Further evaluation is necessary only for structure/aging effect combinations not

covered by the Structural Monitoring Program. -

The applicant stated that the Inservice Inspection Program (AMP B.3.1) and the Structural

Monitoring Program (AMP B.4.3) manage all in-scope structures. The staff reviewed these

programs and documents its evaluation in Section 3.0.3.1 and Section 3.0.3.2.4 of the SER,

respectively. These programs identify all aging effects (e.g., cracking, loss of material, and

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change in material properties), regardless of the causal mechanisms.

Because the Inservice Inspection Program or the Structural Monitoring Program manage all the

FNP structures, the staff concludes that the applicant has adequately addressed the aging of

structures not covered by the Structural Monitoring Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated those

AMR results involving management of aging of structures not covered by the Structural

Monitoring Program for Class I structures, as recommended in the GALL Report. Because the

applicant's AMR results are otherwise consistent with the GALL Report, the staff finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2.9 Aging Management of Inaccessible Areas

In Section 3.5.2.2.9 of the LRA, the applicant addressed aging management 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 due to aggressive chemical attack and cracking, spalling, loss of bond, and loss of

material caused by corrosion of embedded steel could occur in belowgrade inaccessible

concrete areas. The GALL Report recommends further evaluation to manage these aging

effects in inaccessible areas of Groups 1-3, 5, and 7-9 structures, if specific criteria defined in

the GALL Report cannot be satisfied; ISG-3 identified additional requirements. For corrosion of

embedded steel in accessible areas, the applicant manages aging using the structures

monitoring program for Class 1 structures.

The GALL Report (as updated by ISG-3) states that aggressive chemical attack and corrosion

of embedded steel is not significant unless pH is less than 5.5, chlorides are greater than

500 ppm, or sulfates are greater than 1500 ppm. According to ISG-3, a plant-specific program

is required to examine representative samples of belowgrade concrete when excavated for any

reason.

The applicant stated that the requirement for aging management of inaccessible areas for

containment components applies to the aging management of inaccessible areas for Class 1

structures. The staff agrees with the applicant and addresses its evaluation of the aging

management of inaccessible areas for containment components in Section 3.5.2.2.1 of this

SER.

III. Component Supports

The staff reviewed Section 3.5.2.2.2 of the LRA against the criteria in Section 3.5.2.2.2 of the

SRP-LR, which addresses several areas discussed below.

3.5.2.2.10 Aging of Supports Not Covered by Structural Monitoring Program

In Section 3.5.2.2.10 of the LRA, the applicant addressed aging of supports not managed by

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the Structural Monitoring Program.

Section 3.5.2.2.3.1 of the SRP-LR states that the GALL Report recommends further evaluation

of certain component support/aging effect combinations, if they are not covered by the

Structural Monitoring Program. This includes (1)-reduction in concrete anchor capacity due to

degradation of the surrounding concrete for Groups 81-85 supports, (2) loss of material due to

environmental corrosion for Groups B2-B5 supports, and (3) reduction/loss of isolation function

caused by degradation of vibration isolation elements for Group B4 supports. Further

evaluation was necessary only for structure/agirig effect combinations not covered by the

Structural Monitoring Program.

The applicant stated that the Structural Monitoring Program, evaluated in Section 3.0.3.2.4 of

this SER, is applicable to all components in Groups B2 through B5. The applicant also stated

that no further evaluation is required for these components. The Inservice Inspection Program

manages the component supports in Group B1. The applicant also stated that the Inservice

Inspection Program is consistent with GALL AMP XI.S3, "ASME Section Xi, Subsection IWF."

The staff documents its evaluation of the Inservice Inspection Program in Section 3.0.3.1 of this

SER.

The staff determined that the program would identify reduction in concrete anchor capacity due

to degradation of the surrounding concrete. GALL AMP XI.S3 invokes Table IWF-2500, which

calls for the examination of connections to building structures. The staff concludes that the

Inservice Inspection Program is a satisfactory alternative to the Structural Monitoring Program.

On the basis of its review, the-staff finds that the applicant has appropriately evaluated those

AMR results involving management of the aging of component supports not covered by the

Structural Monitoring Program, as recommended in the GALL Report. Because the applicant's

AMR results are otherwise consistent with the GALL Report, the staff finds that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.5.2.2.11 Cumulative Fatigue Damage

As stated in the SRP-LR, the GALL Report identifies cumulative fatigue damage as a TLAA for

support members, anchor bolts, and welds foFGroups B13.1,'B11.2, and B1.3 component

supports, if a CLB fatigue'exists. In LRA'Section 3:5.2.2.11, the applicant stated that the CLB

for the support members, anchor bolts, welds, etc. does not include fatigue analyses.

Generally, steel components are not prone to'fatigue. For the most part,- loads are applied

gradually and remain constant. Support members subjected to fatigue loading conditions are

accounted forby code in their design'- Therefore, this item does not qualify as a TLAA, as

defined in 10 CFR 54.3. The staff finds this acceptable because CLB fatigue analyses do not

exist.

Conclusion',

On the basis of its audit and review, the staff finds that the applicant's further evaluations,

conducted in accordance with the GALL Report, are consistent with the acceptance criteria in

Section 3.5.2.2 of the SRP-LR.' Since the applicant's 'AMR results are otherwise consistent with

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the GALL report, the staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

current licensing basis for the period of extended operation, as required by 1 0 CFR 54.21 (a)(3).

3.5.2.3 AMR Results That Are Not Consistent With or Not Addressed in the GALL Report

3.5.2.3.1 PWR Concrete Containments AMR Results

In Section 3.5.2.1.1 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following programs that manage the aging effects related

to the PWR concrete containments structure:

* Inservice Inspection Program

* Water Chemistry Control Program

* Structural Monitoring Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.5.2-1 of the LRA, the applicant summarized the AMRs for the PWR concrete

containment structure components and identified which AMRs it considered to be not consistent

with the GALL Report.

Staff Evaluation

Table 3.5.2-1 of the LRA indicates that the AMR results of the following listed items are

consistent with the corresponding GALL items for component, material, environment, aging

effects, and AMPs:

* abovegrade concrete dome, wall, ring girder, and buttresses

* belowgrade concrete wall and buttresses

* concrete foundation

* concrete internal structures

* personal airlock and equipment hatch

The staff concurs with the above list.

In discussing Item 3.5.1-3 (Table 3.5.1) of the LRA, the applicant asserted that the FNP AMR

results were consistent with GALL. Item A3A1 of GALL (page 11 A3.6) recommends further

evaluation regarding the SCC of containment bellows. In RAI 3.5-1, the staff requested the

applicant to provide additional information regarding the containment pressure boundary

bellows at FNP, relevant operating experience, and methods used to detect their age-related

degradation. In the RAI, the staff noted that in many cases, VT-3 examination of IWE, and

Type B, Appendix J testing could not detect such aging effects (see NRC IN 92-20).

In its response to RAI 3.5-1, dated March 5, 2004, the applicant stated that the only location

where penetration bellows were used at FNP was in the fuel transfer tube assembly. The

applicant provided the following description of the fuel transfer tube, including the bellows

assembly, relevant operating experience, and testing:

The fuel transfer tube penetrates the containment wall connecting the refueling canal in

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containment with the fuel transfer canal in thb Auxiliary Building. This penetration consists of a

'pipe installed inside a sleeve.- The tube is sealed to the steel liners iri both the refueling canal and

fuel transfer canal. The tube is closed with a blind flange on the containment side and a gate valve

on the Auxiliary Building side. Expansion Joint bellows (single-ply) provide for relative movement

between containment and the Auxiliary Building structures. -'

Portions of the fuel transfer tube are exposed to 'a wetted environment during certain operating

modes. The portions of the fuel transfer tube exposed to this wetted environment are constructed ..from stainless steel. Rigorous chemistry controls limit the concentration of aggressive chemical

species so this environment is not corrosive'to'stainless steel. In addition, the operating

temperature of the water in the refueling canal and the fuel transfer canal is sufficiently low so that

the bellows remain below the threshold temperature for stress corrosion cracking (i.e., <140 'F).

During other operating modes the fuel transfer tube Is exposed to an Inside" environment at

ambient temperature. The Inside environment is'not corrosive to stainless steel: Stainless steel -

bellows'are very compliant (flexible); therefore,' sustained high tensile stre6ss doesnriot exist. 'Since

a corrosive environment and a high level of sustained tensile stress do not exist for the fuel

transfer tube bellows, SCC on penetration bellows is not considered an aging effect requiring

.- management.: -- - -

The staff finds the applicant's response acceptable because it adequately justifies not explicitly

considering the cracking of containment fuel tran'sfer tube bellows an aging-mnanagement item

during the extended period of operation. However,' as the fuel transfer tube 'penetration

represents the containment pressure boundary (refer to Table 3.5.2-1 of the LRA), the Water

Chemistry Control and Inservice Inspectiori Programs will monitor the aging effects

(Appendices B.3.1 and B.2.2 to the LRA).

For seals and gaskets related to containment penetrations, the staff noted that in Item 3.5.1-6

of the LRA, the applicant identified containment] SI and containment leak rate testing as the -

AMPs. -For equipment hatches and air locks'at FNP, the staff agrees with the applicant's

assertion that the Leak Rate Testing Prograni will monitor aging degradation of seals and

gaskets, as they are tested for leak rate after each opening. For other penetrations with seals

and gaskets, in RAI 3.5-2, the staff requested the applicant to provide information regarding the

adequacy of a Type B leak rate testing frequency to monitor aging degradation of seals and

gaskets at FNP.

In its response to RAI 3.5-2, dated March 5, 2004, the applicant noted that it was using Option

B of Appendix J to 10 CFR Part 50 for leak rate test of the containment. The applicant provided

the response in terms of aging rnanagenent and testing of electrical and mechanical

penetrations. The applicant explained that the electrical penetrations have been divided into

three groups for testing purposes, 41 60-V, 600-, and -instrumentation/controI penetrations.

Approximately one-third of the electrical penetrations are to be tested evepy emonthsrwith'

samples from each of the above three groups. The applicant will look at a representative

sample over a short duration to identify any generic aging issue applicable to other electrical

penetrations.

The applicant identified five mechanical penetrations with seals and gaskets, including (1) fuel

transfer tube, (2) spare penetrations 90 and 92 used to run temporary cables'inside the

containment during outages (e'.g.,;SG examinations), and (3) containment integrated leak rate

testing penetrations 71 and 72, which have' been' modified to allow the routing of temporary

cables and hoses inside the containment (e.g.,' SG activities). The applicant stated that these

penetrations were typically opened durin g every refueling outage. The applicant performs an

as-left test after closure following an outage.-

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The staff finds the response acceptable because it indicates that the electrical and mechanical

penetrations involving seals and gaskets will be adequately managed under FNP's containment

Inservice Inspection and Leak Rate Testing Programs to ensure the leak-tight integrity of the

containment structures.

In discussion of Item 3;5.1-12 in Section 3.5.2.2.4 of the LRA, the applicant noted that it

monitors the moisture barrier under the Inservice Inspection Program for aging degradation. In

RAI 3.5-4, the staff noted that the industry experience indicated moisture barrier degradation

with time, and that moisture accumulation in the degraded barrier may likely corrode the steel

liner. The staff requested the applicant to provide information regarding the operating :

experience related to, the degradation of the moisture barrier and the containment liner plate at

FNP. The RAI also r~equested a discussion of acceptable liner plate corrosion before it was

reinstated to the nominal thickness.

In its response to RAI 3.5-4, dated March 5, 2004, the applicant stated that the moisture barrier

is located along the periphery at the mating surface between the containment liner and concrete

fill at elevation 105'"6. The condition of the moisture barrier in 6ach'unit was very good with

hardly any sign of cracking or flaking. Because no significantdegadation of the containment

liner plate and moisture barrier at the interface between the concrete fill and the containment

liner plate had occurred, the applicant performed no boroscopic examination. Moreover, the

applicant provided a detailed description of the liner paint pill-off- liner indentations, and liner

bulging, as well as the corrective actions taken.

Based on the applicant's response, the staff observed that the a5plicant is vigilant in examining

the pressure boundary components of the containments, and it pr6vides'an assurance that

these components will be adequately managed for aging effects during the extended period of

operation.

In RAI 3.5-5, with respect to LRA Item 3.5.1-15, the staff requested the following information:

In 1985, the incident of post-tensioning anchor-head failures had occurred at FNP, Unit 2. The

event is partially documented in NRC Information Notice 85-10 and its Supplement 1. Please

provide a description of the subsequent actions taken, together with the operating experience as to

the effectiveness of the corrective actions taken. Also, indicate, if any other actions are (and will

be) continued in addition to the IWL tendon inspections to ensure the integrity of the tendon

anchor-heads.

In its response to RAI 3.5-5, dated March'5, 2004, the applicant described the event in detail,

and provided the following description of the corrective actions it took:

in order to ensure the continued structural integrity of the containment tendon field anchors in both

units, the following follow-up inspections and tests were performed:

Following one year of service after completion of the tendon inspection and repair effort, all vertical

tendon field anchors in each unit were visually inspected for evidence of moisture.

Following three years of service after completion of the tendon inspection and repair effort,

horizontal and dome tendon field anchors were visually inspected for evidence of moisture and

evidence of failure on a random sample basis to establish a 95% probability with a 95%

confidence level that no failed field anchors exist in either group. -

In addition to the actions described, the tendon surveillances required by the Technical

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Specifications were performed. Tendon sureillances since the incident do not suggest any

abnormal degradation of the tendon system and the results demonstrate that containment

structural integrity has been maintained continuously for both units. No additional actions beyond

the IWL tendon Inspections are planned during the period of extended operation to ensure the

Integrity of the tendon anchor-heads.

The staff finds the applicant's 'corrective actions'and the planned actions to monitor the FN '

post-tensioning system adequate and acceptable because they will ensure the integrity of thie

FNP post-tensioning system during the'period of extended operatio ' -'

For FNP pre-stressing tendons and anchorage components, in addition to the-loss of material'

aging effect due to corrosion, the applicant included cracking as another aging effect to b0

managed by its Inservice Inspection Programn. ''The' staff finds the applicant's approach -

consistent with the plant-specific experience at FNP and the intent of the GALL RepIort and is

therefore acceptable.

For carbon steel liners inside'the containmeht, in' addition to crediting the Structural Monitoring

Program,'the applicant also credited FNP's Borated Water Leakage Assessment and

Evaluation Program with its aging managemen. -The staff finds that this'coordinated approach

addresses the intent of the GALL Report and is therefore acceptable., -

With respect to seals, gaskets, and moisture barriers discussed above, FNP credited the

Inservice Inspection Program (including the Leak Rate Test Program) with managing pressure

boundary items and the Structural Monitoring.Program for managing nonpressure boundary

items. The staff finds' that theapplicant's approach meets the intent of the GALL Report and is

therefore acceptable.

For FNP steel components, except steel support members, anchor bolts, and welds, the

applicant credited the Structural Monitoring Program for their aging management. For the steel

support rembersranchor bolts, and welds, FNP's'Borated Water Leakage Assessment 'and

Evaluation Program is credited for managing their agiing effects. The staff finds this approach

consistent with the GALL Report and is thereforeacceptable.

With respect to refueling cavity and transfer canal miscellaneous steel components; the

applicant stated that Water Chemistry Control Program will manage loss of material due to

corrosion. The applicant further explained that 'SC is not applicable for these components

because they are not subjected to high temperatures and an aggressive environment. The staff

finds the applicant's justification consistent with the GALL Report and is therefore acceptable.'

With respect to FNP's steel containment liner, liner anchors, and integral attachments,-the

applicant credited the Borated Water Leakage Assessment and 'Evalution Program, in

conjunction with the Inservice Inspection Program, to manage the aging of these steel*'

elements. The staff finds the applicant's approach consistent with the" GALL Report'and is

therefore acceptable.

The applicant's AMR for the stainless steel sur-r`p tash rack indicated that no AMP is needed

for this item. This AMR result is consistent with the intent of the GALL Report. and is therefo6e.

acceptable.

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In addition to the Structural Monitoring Program, the applicant credited the Borated Water

Leakage Assessment and Evaluation Program to manage corrosion caused by the leakage of

borated water onto the carbon steel tri-sodium phosphate basket. This is consistent with the

GALL Report and is therefore acceptable.

In Item 3.5.1-10 of the LRA, the applicant discussed the results of its AMR of the concrete

structures inside FNP containments subjected to elevated temperatures. In' Section' 3.5;2.2.3'of

the LRA, the applicant discussed operating experience in which the sustained primary shield

wall temperatures were higher than the established threshold value of 150 OF. As a

precautionary measure, FNP established a monitoring program for RV supports and alignment.

The staff finds the monitoring program established during the CLB acceptable for managing the

effects of relatively higher temperatures near reactor pressure vessel supports for the period of

extended operation.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects that result from contact of the

PWR concrete containments system components with the environments des6cibed in Table

3.5.2-1 of the LRA are consistent with industry 'experience for these material-environmentU

combinations. Therefore, the staff finds that the, applicant identified the applicable aging effects

and associated AMPs appropriate for the material-environment c6rnbinations specified.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended fuuction(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPi credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.5.2.3.2 Auxiliary Building AMR Results,

In Section 3.5.2.1.2 of the LRA, the applicant identified the rrinterials, environments, and

AERMs. The applicant identified the following programs that manage the aging effects related

to the auxiliary building structure:

* .Structural Monitoring Program

* Water Chemistry Control Program

* Fire Protection Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.5.2-2 of the LRA, the applicant summarized the AMRs for the auxiliary building

structure components, and identified which AMRs it considered to be not consistent with the

GALL Report.

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Staff Evaluation -- ; -

Table 3.5.2-2 of the LRA indicates that the AMR results of the following listed items are

consistent with the corresponding GALL items for component, material, environment, aging

effects, and AMPs: - .

* exterior abovegrade and belowgrade concrete, foundation, and interior concrete; roof

slabs and masonry walls foundation; interior concrete

* fire doors and fire seals

* -storage rack assembly

* structural steel components

The staff concurs with the above list.

With respect to the AMR results provided in Table 3.5.2-2 of the LRA (page 3.5-40) for

compressible joints and seals, the staff issued RAI 3.5-7 to request the applicant to discuss

FNP's past operating/inspection experience pertaining to changes in material properties and

cracking of elastomers to justify that the inspection frequency adopted in the Structural

Monitoring Program is adequate to ensure functionality of FNP's compressible joints and seals.

In its response to RAI 3.5-7, the applicant stated the following:

Periodic inspection frequencies have been selected to provide assurance that any age-related degradation is detected at an early time so that appropriate corrective actions can be

Implemented. Initially, this period was set at five years so that the overall condition of each inscope structure or structural component is inspected every five years. Subsequent inspections

have verified that the compressible Joints and seals are performing as required, and degradation has been detected prior to loss of function with the five year inspection frequency. The Structural

Monitoring Program includes provisions to adjust the frequency of inspection based on the

inspection results. The compressible joints and seals constructed of elastomer materials have

performed very well at FNP. There have been minor instances of water seepage past elastomer

compressible joints and seals requiring remedial action.- Seepage occurred at a location on the

bottom elevation of the Auxiliary Building and In the Electrical Cable Tunnels at the interface with

the Auxiliary Building (near the location of the watertight doors) which Is protected by a water stop. This seepage was not the result of age-related degradation but rather was a function of the local

hydraulic conditions. These conditions were identified through normal plant activities including the

Structural Monitoring Program, and remedial action was taken (use of hydrophilic grout). The

Structural Monitoring Program continues to periodically Inspect these areas as part of the spacesbased inspections.

In addition to the elastoner material listed in Table 3.5.2-2, some compressible joints and seals in

'the Auxiliary Building are constructed of a cork material.' This cork material was inadvertently: omitted from the table. The cork material was used dunIng Initial forming of the concrete to fill the

seismic gaps between the floor slabs and vertical walls of the Auxiliary Building and the

Containment wall. ,The cork ensured the required gap was maintained during the forming process ..and acts as seal between adjoining spaces and elevations. In certain locations, these seals

prevent flooding interaction betwee . ; -s^-' - -

,- A - ., -l, - .

There have been isolated cases of the cork joint fillers slipping out of the gap (since the original j Joint design does not provide any substantial retention mechanism (other than friction between the

surfaces). The cork material appears to be in good condition; however, shrinkage and differential

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i

movement between the two mating surfaces is believed to have resulted in the slippage. Where

necessary, the cork was replaced, and in some cases elastomer sealant compounds were used.

The Structural Monitoring Program inspection frequency is adequate to detect the degradation

(slippage) of the cork material prior to loss of any intended function.

The applicant further indicated that the "compressible joints and seals" line item in Table

2.4.2.1, "Auxiliary Building Component Types Subject to Aging Management Review and Their

Intended Functions," should have included "flood barrier' as an intended function. Further, the

auxiliary building AMR summary for the compressible joints and seals line item in Table 3.5.2-2

of the LRA (page 3.5-40) should have been modified accordingly.

The staff finds the applicant's response to RAI 3.5-7 adequate and acceptable because the

applicant's program will adequately manage the aging degradation of compressible seals and

joints.

In RAI 3.5-8a, the staff pointed out the following concern:

Regarding the stainless steel penetration sleeves listed on Table 3.5.2-2 (page 3.5-43)

of the LRA that are exposed to outside environment, no AMP is credited to manage

aging of these components: Depending on the plant site specific parameters that define

the "outside environment," some stainless steel components exposed to sustained,

aggressive outside environment might still be subjected to appreciable loss of material

aging effect.

Therefore, the staff requested the applicant to discuss key characteristics of FNP's outside

environment and its past operating/inspection experience with respect to aging management of

the components listed, and to justify its position that no AMP is needed for the components.

The applicant provided the following response:

Past inspections of stainless steel penetrations and aluminum and stainless steel cable trays,

conduits, ducts, and tube tracks in an outside environment have identified only minor surface

oxidation and discoloration. Past inspections do not indicate any appreciable loss of material

aging effect. Corrosion of stainless steel and aluminum components has typically been associated

with marine/industrial environments where the presence of significant amounts of contaminants .

results in localized corrosion or stress corrosion. FNP is located in a rural environment away from

the coastline and with few sources of industrial pollutants. These components are not insulated,

eliminating the potential for the insulation to retain moisture and leach halides onto the surfaces.

Rain has been found to wash contaminants off of un-insulated components, instead of

concentrating them. Therefore, these components are not considered to be exposed to a

chemically aggressive or acidic environment. FNP operating experience confirms this position.

The staff finds the applicant's response to RAI 3.5-8a adequate and acceptable because it

provides a plant-specific and operating experience-based justification for not considering the

stainless steel penetration sleeves in its AMPs.

Regarding the fire doors listed in Table 3.5.2-2 of the LRA, the applicant credited the Structural

Monitoring Program to manage the loss of material aging effect. The applicant's approach is

consistent with the GALL Report, and is therefore acceptable.

For carbon steel penetration sleeves in auxiliary buildings, the Structural Monitoring Program is

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credited to manage loss of material aging effect. This is consistent with NUREG-1801 and is

therefore acceptable.

For FNP steel components, except steel support members, the applicant credited the Structural

Monitoring Program to manage the aging effebt for loss of material. For steel support

members, the applicant credited the Borated Water Leakage Assessment and Evaluation

Program to manage'the aging effects resulting from boric acid corrosion. The staff finds the

applicant's approach to be consistent with the GALL Report and is therefore acceptable.

The staff's RAI 3.3-17 requested the applicant to address the following two items:

a. Referring to Table 3.3-1 of the LRA, Item 3.3.1 -11 states in the discussion that the FNP

Structural Monitoring Program (Appendix B.4.3) will manage loss of material of the carbon

steel portions of the new fuel storage racks." Discuss'applicable non-carbon steel

materials (e.g., aluminum; stainless steel, etc') that are'used In FNP's new fuel rack

assemblies, their environments, FNP specific aging related operating experience, and the

results of their aging management review. Also, explain why these new fuel rack

assemblies'are not explicitly listed In section B.4.3.5, Program Scope, of the FNP's

Structural Monitoring Program.

b. Referring to Table 3.3-1 of the LRA, item 3.3.1-13 states in the discussion that the spent fuel storage racks are not considered susceptible to stress corrosion cracking since the'.

temperature of the borated water in the spent fuel pool is normally less than this threshold ----- temperature for SCC. Elaborate on FNP's use of the phrase: "...normally less than this

threshold temperature for SCC," define the threshold temperature referred to therein,

explain expected or applicable abnormal conditions implied in the phrase, and discuss

-applicable SCC related operating experience of FNP spent fuel storage racks and

associated valves.

In its letter dated April 5,'2004, the applicant provided the following response to RAI 3.3-17:

The Auxiliary Building New Fuel Storage Area is adjacent to the Spent Fuel Pool (SFP) area, but is

a separate area designed for dry storage of new fuel assemblies prior to transfer into the SFP.

The new fuel storage rack assemblies are located In an inside (dry) environment. The Inside"

environment is described in Section 3.0A of the LRA. Each rack is composed of individual vertical

cells that can be fastened together in any number to form a module that can be firmly bolted to the

floor of the new fuel storage area. All surfaces that come into contact with the fuel assemblies are

made of austenitic stainless steel, whereas the supporting structure is carbon steel. The

component type includes the structural steel rack frame members, stiffeners, and anchors into the

reinforced concrete building structure. -, .. -

A review of FNP operating experience performed for development of the FNP LRA indicates that

there has been no age-related degradation of the stainless steel material In an Inside (dry)

environment.. : *. ,

A spaces approach Is used for performing the Structural Monitoring Program (SMP) inspections. Therefore, the Structural Monitoring Program scope in section B.4.3.5 lists only the in-scope structure (e.g., Auxiliary Building) but not every component located inside the structure. New fuel

rack assemblies are a structural component type located in the'Auxiliary Building and thus are

inspected by the program.

The applicant-further responded to RAI 3.3-17 by stating the following:

FNPapplies a conservative threshold temperature of 140 'F for initiation of SCC in austenitic

stainless steel components exposed to borated water. Extensive industry data based on actual

operating experience and laboratory testing Indicate that initiation of SCC is unlikely to occur at

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temperatures less than 140 0F unless the materials are sensitized and exposed to harsh marine

wet-dry cycling conditions. This SCC threshold limit is' consistent with EPRI TR 1003056,

'Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 3," November

2001.

FNP maintains a 105 0

F operational temperature limitation on the spent fuel pool except during

refueling outages; A 130 'F operational temperature limitation is maintained during refueling

outages. Actual operating temperatures in the spent fuel pool are below these operational limits..

To date, there have been no fuel pool temperature excursions exceeding 140 "F. Conservatively

postulated abnormal core offload or accident scenarios could potentially exceed the 140 OF

threshold forinitiation of SCC (FNP UFSAR, Rev. 17, Section 9.1.3.1.1) but are not representative

of actual operation.

A review of FNP operating experience performed for development of the FNP LRA did not identify

any SCC-related experience associated with the spent fuel storage racks or FNP Spent Fuel Pool

Cooling and Cleanup System austenitic stainless steel components. Therefore, existing industry

data and FNP specific operating experience indicate that cracking due to SCC is not an aging

effect requiring management for the FNP spent fuel storage racks and FNP Spent Fuel Pool

Cooling and Cleanup System components exposed to borated water.

The staff finds that the applicant's response to RAI 3.3-17 is consistent with the GALL Report

and is therefore acceptable.

In RAI 3.5-12, the staff requested the following with respect to aging management of Group 5

liners:

Item 3.5.1-23, Table 3.5.1 (page 3.5-27) of the LRA lists Water Chemistry and monitoring of spent

fuel pool water level as AMPs credited to manage aging of Group 5 liners. FNP stated under the

discussion column that AMR results are consistent with NUREG -1801 with some minor exceptions

and loss of material due to localized corrosion will be managed by FNP Water Chemistry Control

Program. Clarify what constitutes the above referenced 'some minor exceptions"? Is spent fuel

pool water level monitoring credited as part of the FNP's AMPs for aging management of this

item? If not, provide the basis for not crediting the spent fuel pool water level monitoring program

as indicated in NUREG-1801, item Ill A5.2-b (page III A5-10).

In its response to RAI 3.5-12, the applicant stated the following:

The Group 5 liners (spent fuel pool, refueling cavity, and canal) are age-managed by the Water

Chemistry Control Program . The NUREG-1801 aging management review (AMR) results in Table

3.5.1 for item 3.5.1-23 indicate two aging effects/mechanisms for the Group 5 liners: loss of

material due to crevice corrosion, and stress corrosion cracking (SCC). In the discussion column

for this item, SNC states 'SCC is not applicable for reactor cavity or spent fuel pool liners because

it is not subject to high temperatures and an aggressive environment." This was termed a "minor

exception." SNC provided additional information on this determination in our April 7, 2004

response to RAI 3.3-17b (SNC letter number NL-04-0473). Although SCC was determined to not

be applicable, there is no impact on relying on the Water Chemistry Control Program as the AMP

for the Group 5 liners.

Monitoring of the spent fuel pool water level is not credited as part of aging management for the

Group 5 liners. The effectiveness'of the Water Chemistry Control Program at managing crevice

corrosion in stainless steels in a borated water environment has been demonstrated in industry

and FNP-specific operating experience.

SNC does not consider spent fuel pool water level monitoring adequate to detect small leaks in the

pool liner. The large volume of the pool, pool inventory manipulations to support fuel movement

activities, and normal make-up requirements (e.g., for evaporative losses) would mask any pool

level impact. FNP confirms SFP liner integrity by periodic monitoring of the pool's leak chase drain

system. This system consists of a leak chase that collects leakage into the area between the SFP

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liner and the concrete retaining wall. The tell-tale drain valves are opened periodically (currently

done at least annually), and any water collected is volumetrically measured and sampled for boron

concentration.

The staff finds that the above operating experience-based justification meets the intent of the..

GALL Report, and therefore RAI 3.5-12 is closed.

With respect to the applicant's AMR results covering cable fire wrap and fire stops, the staff

requested the following additional information in'RAI'3.5-15:

In its response to RAI 2.3.3.13-2, the applicant asserted that cable fire wrap and fire stops

consisting of Kaowool and Maranite situated In an Inside environment have no aging effect.

requiring management; therefore, no AMP is required for the components (refer to the last table

provided on page E2-19 of Enclosure 2 to SNC's letter dated April 7, 2004). The applicant is

requested to provide additional Information including vendor provided or lab tested material aging

data of both the Kaowool and Maranite materials,' and plant specific operating experience based

aging data for the same In order to support the above assertion.

The applicant responded to RAI 3.5-15 by stating the following:

Additional information Is provided, In the form of vendor provided aging data and plant specific

aging data, for Kaowool and Marinite materials. (Note that 'Marinite" was misspelled as 'Maranite"

in the response to RA! 2.3.3.13-2.) -

Vendor data indicates that Kaowool is an inorganic ceramic fiber material that is very stable under --

normal and extreme plant temperatures and common plant conditions, and does not exhibit age

related degradation. It is produced from kaolin, provided as a fire proof insulation blanket intended

for the physical separation of divisional electrical cables. Kaowool offers excellent handleability

and high temperature stability. It has a melting point of 3200 OF and a continuous use limit of

200"0 F. Kaowool does not contain organic binders, provides excellent resistance to chemical

-attack (except hydrofluoric and phosphoric acid and strong alkalies such as Na2O and K20) and

thermal properties are unaffected by oil or water, after drying. ,.-

Vendor data indicates that Marinite boards are very durable, hard surfaced boards that do not exhibit age

related degradation under normally expected plant environments and conditions. Marinite boards are

incombustible structural insulation material formed from calcium silicate with inert fillers and reinforcing,

agents. These boards, usually ranging in thickness from 1h inch to 2 inches, can be cut or machined from

4'xB' panels into various shapes and sizes and erected as barriers to provide fire safety and temperature

control. They are frequently used In fire safety applications such as fire stops, fire walls, cable trays and fire

doors. Marinite structural Insulation Is highly damage-resistant, non-corroding, and extremely waterresistant. Marinite has a melting point greater than 2300 "F and Is stable under normal ambient conditions.

A review of specific plant operating experience does not Indicate any Instances of age related'

degradation of Kaowool fire wrap or Marinite fire stops.

The staff finds the above response' adequate to resolve RAI 3.5-15 because the vendor data

provided do conservatively bound the environments to which FNP cable fire wrap and fire stops

are exposed. Further, a review of specific plant operating experience did not indicate any

instances of age-related degradation of Kaowool fire'wrap or Marinite fire stops. '

With respect to the applicant's AMR results covering the sprayed on or-troweled on fire- -7

resistive material, the staff issued RAI 3.5-16, which includes the following:

In its response to RAI 2.3.3.13-3, the'applicant states, as part of its proposed 'Plant-specific note

48' (refer to the last paragraph of page E2-20 of the same reference), that the sprayed-on or

troweled-on fire resistive material has no aging effects requiring aging management. The

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i

applicant is requested to provide pertinent vendor generated or lab-tested data as well as plantspecific operating experience-based aging data for the sprayed-on or troweled-on fire resistive

material to further support the above statement.

The applicant responded to RAI 3.5-16 by stating the following:

The fire resistive material applied to the structural steel and doors referred to in RAI 2.3.3.13-3

include Monokote and Albi Clad 89S. Vendor data Indicates that these fire resistive materials are

very durable and stable materials under normally expected plant environments and conditions.

Vendor information indicates that Monokote is a cementitious material that bonds tightly to steel

surfaces, forming a hard surface that does not spall, dust, or flake. Testing per ASTM E937

indicates that Monokote does not promote corrosion. The vendor data states that Albi Clad 89S is

a fire retardant intumescent mastic that dries to a hard, durable finish. Both Monokote and Albi

Clad have undergone testing that demonstrates their fire resistance.

A review of plant specific operating experience does not indicate any instances of age related

degradation of fire resistive material on structural steel components. The Structural Monitoring

Program inspects the structural steel and doors with the fire resistive material and would detect

degradation of the fire resistive material coating.

The staff finds the above response acceptable because vendor data indicate that both

Monokote and Albi Clad 89S fire-resistive materials are very durable and stable under normally

expected plant environments and conditions. In addition, a review of plant-specific operating

experience did not indicate any instances of age-related degradation of fire-resistive material on

structural steel components. Therefore, RAI 3.5-16 is closed.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls,' the'staff finds that the aging effects.that result from contact of the

auxiliary building system components with the environments described in Table 3.5.2-2 of the

LRA are consistent with industry experience for these material-environment combinations.

Therefore, the staff finds that the applicant identified the applicable aging effects and

associated AMPs appropriate for the material-environment combinations specified.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.5.2.3.3 Diesel Generator Building AMR Results

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. The applicant identified the following programs that manage the aging effects related

to the diesel generator building structure:

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* Structural Monitoring Program

* ^Fire Protection Program

In Table 3.5.2-3 of the LRA, the applicant summarized the AMRs for the diesel generator

building structure components and identified wvhich AMRs it considered to be not consistent with

the GALL Report.

Staff Evaluation

Table 3.5.2-3 of the LRA indicates that the AMR results of the following listed items are

consistent with the corresponding GALL items for component, material, environment, aging

effects, and AMPs:

* exterior abovegrade and exterior bblowgr6ade concrete,'foundation, and interior

concrete, roof slabs, and masonry walls foundation; interior concrete

* fire doors and fire seals

*' 'masonry walls '

* structural steel components

The staff concurs with the above list.

Table 3.5.2-3 (page 3.5-45) of the LRA indicate's that the compressible joints and seals

consisting of fiber, foams, and ceramics used in FNP's diesel generator building that are

exposed to belowgrade environments have no applicable aging effect requiring management,

and therefore no AMP is credited to manage their aging. Because sustained exposure to an

aggressive belowgrade environment might resultifi'aging of these components, RAI 3.5-9.

requested the applicant to discuss key characteristics of its belowgrade environment, as well as

its past operating/irispection experienice with iespect to aging management of these

components, and to justify its position that n6AMP is'needed for the listed components.

The applicant responded to RAI 3.5-9 by stating that the belowgrade environment at FNP is not

aggressive. Soil used in the vicinity of the diesel generator building and other seismic'Category

I structures is controlled and compacted backfill. The ground water is considered

nonaggressive'because the chlorides, gsulfates, and pH are well within' the ranges identified as

nonaggressive by EPRI TR-1 002950, Revision 1, "Aging Effects for Structures and Structural

Components (Structural Tools)." Recent water samples from the service water pond and an:.

onsite construction well have yielded a pH ranging from 6.7 to 7.1 (greater than an aggressive

pH value of less than 5.5), chloride solutions ranging from 2.0 ppm to 3.7 ppm (less than an

aggressive chloride level greater than 500 ppm), and sulfate solutions ranging from 5.3 ppm to

6.4 ppm (less than an aggressive sulfate level greater than 1500 ppm). The applicant further

stated that there is no histoiryof aging degradation or failure of compressible joints and seals

consisting of fiber, foams, and ceramics exposed .to a belowgrade environment. '

The staff finds that the above plant operating experience-based justification, in conjunction with

the fact that the FNP site ground water is nonaggressive, forms an adequate basis for closure

of RAI 3.5-9.

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I

Regarding the nonfire doors listed in Table 3.5.2-3 of the LRA, the applicant credited the

Structural Monitoring Program to manage the loss of material aging effect. The applicant's

approach is consistent with the GALL Report, and is therefore acceptable.

For carbon steel penetration sleeves in the diesel generator building, the applicant credited the

Structural Monitoring Program with managing the loss of material aging effect. This is

consistent with the GALL Report, and is therefore acceptable.

On the basis of its review of the LRA and the additional information included in the applicant's

response to the above RAls, the staff finds that the aging effects that result from contact of the

diesel generator building system components with the environments described in Table 3.5.2-2

of the LRA are consistent with industry experience for these material-environment

combinations. Therefore, the staff finds that the applicant identified the applicable aging effects

and associated AMPs appropriate for the material-environment combinations specified.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d).

3.5.2.3.4 Turbine Building AMR Results

Summary of Technical Information in the ApDlication

In Section 3.5.2.1.4 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following program that manages the aging effects related

to the turbine building structure:

* -Structural Monitoring Program

In Table 3.5.2-4 of the LRA, the applicant summarized the AMRs for the turbine building

structure components and identified which AMRs it considered to be not consistent with the

GALL Report.

Staff Evaluation

Table 3.5.2-4 of the LRA indicates that the AMR results of the following listed items are

consistent with the corresponding GALL items for component, material, environment, aging

effects, and AMPs:

* exterior abovegrade and exterior belowgrade concrete, foundation, and interior concrete

and roof slabs

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* 'structural steel components ' -"' 'r * A -

The staff concurs with the above list.

On the basis of its review of the LRA, the staff finds that the aging effects that result from

contact of the turbine building system components with the environments described in Table

3.5.2-4 of the LRA are consistent with industry experience for these material-environment

combinations. Therefore, the staff finds that the applicant identified the applicable aging effects

and associated AMPs appropriate for the material-environment combinations specified. ,. : .. -.. . .

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that theintended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR ,

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplemelit program summaries'and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d).

3.5.2.3.5' Utility/Piping Tunnels AMR Results'

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. The applicant identified the following program that manages the aging effects'related

to the utility/piping tunnel structures:

Structural Monitoring Program ' .

In Table 3.5.2-5 of the LRA, the applicant summarized the AMRs for the utility/piping tunnel

structures components, and identified which AMRs it considered to be not consistent with the

GALL Report.

Staff Evaluation - -

Table 3.5.2-5 of the LRA indicates that the AMR results of the following listed items are

consistent with the corresponding GALL items for component, material, environment, aging

effects, and AMPs: - - - -

* exterior abovegrade and exterior belowgrade concrete

* structural steel components

The staff concurs with the above list.

Section 3.5.2.3.3 of this SER provides the staff's evaluation of compressive joints and seals

listed in Table 3.5.2-5 of the LRA.

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On the basis of its review of the LRA, the staff finds that the aging effects that result from

contact of the utility/piping tunnels system components with the environments described in

Table 3.5.2-5 of the LRA are consistent with industry experience for these material-environment

combinations. Therefore, the staff finds that the applicant identified the applicable aging effects

and associated AMPs appropriate for the material-environment combinations specified.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d).

3.5.2.3.6 Water Control Structures AMR Results

Summary of Technical Information in the Application

In Section 3.5.2.1.6 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 water control structures:

* Structural Monitoring Program

* Service Water Pond Dam Inspection

* Fire Protection Program

In Table 3.5.2-6 of the LRA, the applicant summarized the AMRs for the water control

structures components, and identified which AMRs it considered to be not consistent with the

GALL Report.

Staff Evaluation

Table 3.5.2-6 of the LRA indicates that the AMR results of the following listed items are

consistent with the corresponding GALL items for component (with minor variations in

component types), material, environment, aging effects, and AMPs:

* exterior abovegrade and exterior belowgrade concrete, foundation and interior concrete,

roof slabs, and masonry walls

* fire doors and nonfire doors

* dams, embankment, and fire seals

* structural steel components

The staff concurs with the above list.

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The pond dam/dike at FNP is an earthen structure with water control components fabricated of

concrete and steel. The applicant credited the Structural Monitoring Program to manage the

loss of material resultin'g from corrosion of steel components. For dams and embankment

structures, the applicant credited the Service Water Pond Damr Inspection Program to manage

loss of form (earthen embankment) and loss of material aging effects; In Section B.3.3.1 of

Appendix B to the LRA, the applicant asserted that it inspects the service water pond dam and

spillway on a periodic basis in accordance with'RG 1.127, "Inspection of Water-Control

Structures Associated with Nuclear Power Plants." The staff determined that the.applicant's

approach is consistent with the GALL Report, and is therefore acceptable.

For carbon steel stop logs exposed to raw water, the applicant credited the Service Water Pond

Dam Inspection Program with managing the loss of material aging effect. -For the stainless

steel traveling screen exposed to raw water, the applicant credited the Structural Monitoring

Program to manage the loss of material aging effect. This approach is consistent with the

GALL Report, and is therefore acceptable.

On the basis of its review of the LRA, the staff finds that the aging effects that result from

*contact of the water control structures system components with the environments described in

Table 3.5.2-6 of the LRA-are consistent with industry experience for these material-environment

combinations. Therefore, the staff finds that the applicant identified the applicable'aging effects

and associated AMPs appropriate for the material-environment combinations specified.

Conclusion.'

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR-.

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d)::

3.5.2.3.7 Steel Tank Structures (Foundations and Retaining Walls) AMR Results

Summary of Technical Information in the Application -

In Section 3.5.2.1.7 of the LRA, the applicant identified the materials, environments, and

AERMs. The applicant identified the following program that manages the aging effects related

to the steel tank structures:

Structural Monitoring Program ;

In Table 3.5.2-7 of the LRA; the applicant summarized the AMRs for the steel tank structures

components, and identified which AMRs it considered to be not consistent with the GALL

Report.

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Staff EvaluationTable 3.5.2-7 of the LRA indicates that the AMR results of the following listed items are

consistent with the corresponding GALL items for component (with minor variations in

component types), material, environment, aging effects, and AMPs:

* exterior abovegrade concrete (shield and retaining walls), concrete pedestals and

foundation

* bolting

* structural steel components

The staff concurs with the above list.

The steel tank structures at FNP consist of concrete shield, retaining wall, pedestals, and

foundation, together with various steel components and bolting. The applicant credited the

Structural Monitoring Program to manage the loss of material, cracking, and change in material

properties aging effects. This approach is consistent with the GALL Report, and is therefore

acceptable.

On the basis of its review of the LRA, the staff finds that the aging effects that result from

contact of the steel tank structures (foundations and retaining walls) system components with.

the environments described in Table 3.5.2-7 of the LRA are consistent with industry experience

for these material-environment combinations. Therefore, the staff finds that the applicant

identified the applicable agingdeffects and associated AMPs appropriate for the materialenvironment combinations specified.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.5.2.3.8 Yard Structures AMR Results

Summary of Technical Information in the Application

In Section 3.5.221.8 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 yard structures:

* Structural Monitoring Program

* Fire Protection Program

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In Table 3.5.2-8 of the LRA, the applicant summarized the AMRs for the yard structures

components, and identified which AMRs it'coiidered to be not consistent with the GALL

Report.

Staff Evaluation

Table 3.5.2-8 of the LRA indicates that the AMR results of the following listed items are -

consistent with the corresponding GALL items for component (with minor variations in

component types), material, environment, aging'effects, and AMPs:

* concrete foundation'

* masonry walls

* fire doors

* bolting and equipment frames and housing

* structural steel components

The staff concurs with the above list.

With the exception of the carbon steel fire doors for which the Fire Protection Program is

credited to manage the loss of material aging effect, the applicant credited the Structural

Monitoring Program tor'manage loss of material, cracking: and change of material properties

aging effects for the 'rest of the yard structural components. 'The staff finds this approach

consistent with the GALL Report, 'and is therefore acceptable.

On the basis of its review of the LRA, the staff finds that the aging effects that result from

contact of the yard structures system components with the environments described in Table

3.5.2-8 of the LRA a're consistent with industry experience for these material-environment

combinations. Therefore, the staff finds that the applicant identified the applicable aging effects

and associated AMPs appropriate for the material-environment combinations specified. -

v . . .. .-

Conclusion -: -

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis'for the period of extended operation, as required by 10 CFR

54.21 (a)(3). ".

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d).

3.5.2.3.9 Component Supports AMR Results --

Summarny'of Technical Information in the ADplication -

In Section 3.5.2.1.9 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 component supports:

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* Structural Monitoring Program

* Inservice Inspection Program

* Borated Water Leakage Assessment and Evaluation Program

In Table 3.5.2-9 of the LRA, the applicant summarized the AMRs for the component supports

and identified which AMRs it considered to be not consistent with the GALL Report.

Staff Evaluation

Table 3.5.2-9 of the LRA indicates that the AMR results of the following listed items are

consistent with the corresponding GALL items for component (with minor variations in

component types), material, environment, aging effects, and AMPs:

* concrete foundation

* masonry walls

a fire doors

* bolting and equipment frames and housing

* structural steel components

The staff concurs with the above list.

The applicant credited the Structural Monitoring Program with managing the loss of material

aging effect on battery racks and RPV carbon steel supports. The applicant credited the

Borated Water Leakage Assessment and Evaluation Program with managing the loss of

material resulting from boric acid corrosion. This approach is consistent with the GALL Report,

and is therefore acceptable.

In part b of RAI 3.5-8, the staff asked the applicant to address the observation that Table

3.5.2-9 (page 3.5-64) of the LRA indicates that FNP cable trays, conduits, ducts, and tube

tracks that are made of aluminum and stainless steel and exposed to inside and outside

environments have no applicable AERM, and, therefore, no AMP is credited to manage their

aging. Sustained exposure to a chemically aggressive or acidic outside environment might

result in aging of these components.

The applicant responded to RAI 3.5-8, part b, that past inspections of stainless steel

penetrations and aluminum and stainless steel cable trays, conduits, ducts, and tube tracks in

an outside environment have identified only minor surface oxidation and discoloration. Past

inspections do not indicate any appreciable loss of material. Corrosion of stainless steel and

aluminum components has typically been associated with marine/industrial environments in

which the presence of significant amounts of contaminants results in localized corrosion or

stress corrosion. The plant is located in a rural environment away from the coastline and with

few sources of industrial pollutants. These components are not insulated, eliminating the

potential for the insulation to retain moisture and leach halides onto the surfaces. Rain has:

been found to wash contaminants off uninsulated components, instead of concentrating them.

Therefore, these components are not considered to be exposed to a chemically aggressive or

acidic environment. Operating experience at FNP confirms this position. The staff finds the

applicant's response to RAI 3.5-8 part b acceptable.

In its review of Tables 3.5.2-9 and 3.5.1 (Item 3.5.1-32) of the LRA, the staff determined that it

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needed additional information related to these tables and requested the applicant to respond to

the following RAls.

RAI 3.5-13 is related to ASME Class 1, 2, and 3 piping and Class MC component supports and

states the following': . .

For American Society of Mech6nical Engineers'(ASME) Class 1, 2, and 3 piping and Class MC

components support members, NUREG-1801, GALL Report, calls for ASME Section Xl,

Subsection IWF Program to manage aging effects due to loss of material, pitting and general

corrosion of carbon steel support members, welds, bolted connections, and support anchorages

(refer to GALL Report Ill B1.1.1-a and Ill Bl .2.1-a). However, in Table 3.5.2-9 (page 3.5-62) of the

LRA, the applicant credited Structural Monitoring Program instead of the Inservice Inspection

Program for managing aging of the same support members/elements. The applicant is requested

to discuss the basis for taking such exceptions to the GALL Report.

RAI 3.5-14 pertains to constant and variable load spring hangers, guides, stops, sliding

surfaces, and vibration isolators and states the following:

For constant and variable load spring hangers, guides, stops, sliding surfaces, and vibration

isolators listed in Table 3.5.2-9 of the LRA, GALL Report calls for ASME Section Xl, Subsection

IWF for aging management of these components; whereas FNP opted to credit Structural

Monitoring Program for managing aging of these components. Additionally, Item 3.5.1-32 in Table

3.5.1 of the LRA states a position, under its discussion column, that FNP does not consider loss of - mechanical function to be an aging effect requiring management based on the plant operating

experience, contrary to that of GALL Report (refer to GALL Report Sections III B1.1.3-a, IlIl

B1.2.2-a and IlIl B1.3.2-a).- The applicant is requested to justify these deviations from the GALL

Report.'

In its response to RAI 3.5-14, the applicant stated the following:

SNC offers the following clarification on the applicability of the Inservice Inspection Program

(ASME Subsection IWF Program) and the Structural Monitoring Program to the component type

'Constant and variable load spring hangers, guides,'stops; sliding surfaces; vibration isolators (For

ASME piping and components)" In LRA Table 3.5.2-9 (page 3.5-63).

Consistent with the GALL Report (items ill B1.1.3-a and IlIl B1.2.2-a), SNC confirms the FNP ISI

Program (which includes the ASME Section Xl, Subsection IWF Program) is credited to manage

aging effects due to loss of material for this component type. SNC also credits the Structural

Monitoring Program In addition to '(not in lieu of), the Inservice Inspection Program for managing

*aging of these components. These components are also inspected under the FNP Structural

Monitoring Program and therefore were Identified as such In the LRA table.

As stated I6 the discussion column for ltem 3.5.1-32 In Table 3.5.1 of the LRA, SNC does not

consider loss of mechanical function (due tdoforosion, distortion, dirt, overload,-etc.) to be an -

aging effect requiring management at FNP for the Groups B1.1, B1.2 and B13.3 support members,

anchor bolts, welds, spring hangers, guides, stops, and vibration isolators. Review of the FNP

operating experience did not indicate loss of mechanical function due to corrosion or dirt as an

'aging effect at FNP.' Loss of function due to distortion or overload is a design/corrective action

issue and not the result of aging. Although SNC did not Identify loss of mechanical function as an

aging effect, the AMP credited by SNC to manage aging' in these components (i.e., ISI Program) is

consistent with the GALL Report program for managing loss of mechanical function.

The staff finds the above response to RAI 3.5-14 bonsistent with'the intent of the GALL Report,

and therefore RAI is considered closed.

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Conclusion

On the basis of its review of the LRA and the additional information included in the applicant's

response to the RAls, the staff finds that the aging effects that result from contact of the

component supports with the environments described in Table 3.5.2-9 of the LRA are

consistent with industry experience for these material-environment combinations. Therefo're,

the staff finds that the applicant identified the applicable aging effects and associated AMPs

appropriate for the material-environment combinations specified.

3.5.3 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that the

aging effects associated with the containments, structures, and component supports will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging of the

containments, structures, and component supports, as required by 10 CFR 54.21 (d).

3.6 Aging Management of Electrical Components

The applicant described its AMR of electrical and instrumentation and controls (I&C)

components in Section 3.6 of the LRA. The staff reviewed this section of the LRA to determine

whether the applicant has demonstrated that the effects of aging on the electrical and l&C

components will be adequately managed during the period of extended operation, as required

by 10 CFR 54.21 (a)(3).

3.6.1 Summary of Technical Information in the Application

In Table 3.6.1 of the LRA, "Summary of the Aging Management Evaluations for Electrical

Components in Chapter VI of NUREG-1 801," the applicant provided a summary comparison of

its aging management activities with the aging management activities evaluated in the GALL

Report for the electrical component groups. In Table 3.6.2-1 of the LRA, the applicant provided

a summary comparison of the FNP aging management activities with the aging management

activities evaluated in the GALL Report for the electrical component groups. In this table, the

applicant also summarized the materials of construction, service environments, AERMs, and

the credited AMP for each of the electrical component groups. The applicant also provided a

detailed discussion of its AMR in Section 3.6.2.1.1 of the LRA.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of. condition reports and discussions with

appropriate site personnel t6 identifyAERMs. The applicant's review of industry operating

experience included a review of the GALL Report and operating experience issues identified

since the issuance of the GALL Report in 2001.

The applicant conducts its ongoing review of plant-specific and industry operating experience in

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accordance'with the FNP, Unitsi'1 and 2, 6per''ating Experience' Program.

3.6.2 Staff Evaluation -

The staff reviewed 'Section 3.6 of the LRA to determine if the applicant provided sufficient

information to demonstrate that the effects of aging on the electrical components and

component groups that are within the scope of license renewal and subject to an AMR will be

adequately managed, so that the intended functions will be maintained consistent with'the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff performed an audit and review to confirm the applicant's claim that certain identified

AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters

described in-'the GALL Report.' However,' the staff did determine that the applicant presented'

applicable material in the LRA and identified the app'ropriate GALL AMPs. The staff

'documented its evaluations of the AMPs in Section 3.0.3 of this SER.' The FNP Audit and

Review Report, summarized in Section 3.6.2.1 of this SER, details the staff's evaluation of the

audit and review for these AMRs.

The staff also audited those AMRs that were consistent with the GALL Report and for which

'further evaluation is recommended. During the audit and review, the staff concluded that the'

applicant's further evaluations were consistent with the acceptance criteria in Section 3.6.2.2 of

the SRP-LR. The FNP Audit and Review Report, summarized in Section 3.6.2.2 of this SER,

details the staff's evaluation of the audit and review for these AMRs.

The staff conducted a technical review of the remaining AMRs that were not consistent with the

:GALL Report. The review evaluated whether the applicant identified all plausible aging effects

and listed appropriate aging effects for the material-environment combinations specified.

Section 3.6.2.3 of this SER documents the details of the staff's review and evaluation for these

'AMRs that are not consistent with the GALL Report.

Finally, the staff reviewed the AMP summaries in'the FSAR Supplement to ensure that they

'adequately describe the programs credited with managing or monitoring aging for the reactor

system components. ' f 

-Table 3.6-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in Section 3.6 of the LRA that are addressed in the GALL Report.'

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Table 3.6-1 Staff. Evaluation for Electrical Components in the GALL Report

I

Component Group-l ""A..Lng EfectV -M'i WIRhuinGEALU GLL ~ 

-- MPInLA A P.;i -- 

S~.taff.t ' v d-uAPIn.'. aualmw

:..-,.,',--l t-.'Mechan sm''-l '!w r V.N~t+'^x' '8lg.

Electrical Degradation due to EQ of electric TLAA Consistent with

equipment subject various aging components GALL, which

to 10 CFR 50.49 mechanisms recommends further

environmental evaluation. (See

qualification Section 4.4)

requirements

Item Number

3.6.1-1

Electrical cables Embrittlement, AMP for electrical Non-EQ Electrical Consistent with

and connections not cracking, melting, cables and Cables Exposed to GALL, which

subject to discoloration, connections not Adverse Localized recommends no

10 CFR 50.49 swelling, or loss of subject to Environments and further evaluation.:

environmental dielectric strength 10 CFR 50.49 EQ Inaccessible (See Section

qualification leading to reduced requirements Medium Voltage 3.6.2.1)

requirements insulation Cables Program

Item Number resistance; (Appendix B.5.6.2)

3.6.1-2 electrical failure,

caused by thermal!

thermoxidative

degradation of

organics; radiolysis

and photolysis

(ultraviolet UVI

sensitive materials

only) of organics;

radiation-induced

oxidation; moisture

intrusion

Electrical cables Embrittlement, AMP for electrical Non-EQ Electrical Consistent with

used in' cracking,' melting, cables used in Cables Used in GALL, which

instrumentation discoloration, ' instrumentation Instrumentation recommends no

circuits not subject swelling, or loss of circuits not subject Circuits Program further evaluation.

to 10 CFR 50.49 dielectric strength to 10 CFR 50.49 (Appendix B.5.6.1) (See Section

EQ requirements leading to reduced EQ requirements 3.6.2.1)

that are sensitive to insulation

reduction in resistance;

conductor insulation electrical failure

resistance caused by thermal/

Item Number thermoxidative

3.6.1-3 degradation of

organics; radiationinduced oxidation;

moisture intrusion

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Componert Grip "' Eff ' ALAMPi LRA< Sff Etl - Mechanism *. epXr f -.

Inaccessible Formation of water AMP for- -- Non-EQ Electrcal Consistent with

medium-voltage trees' localized inaccessible Cables Exposed to GALL, which

(2 kV to 15 kV) damage leading to medium-voltage Adverse Localized recommends no

cables (e.g., electrical failure cables not subject Environments and further evaluation.

installed in conduit (breakdown of to 10 CFR 50.49 Inaccessible - (See Section

or directly buried) insulation) caused EQ requirements Medium Voltage 3.6.2.1)

not subject to by moisture Cables Program

10 CFR 50.49 EQ intrusion and water (Appendix B.5.6.2)

requirements trees

Item Number

3.6.1-4

Electrical - Corrosion of Boric acid corrosion None Consistent with

connectors not connector contact . GALL, which

subject to surfaces caused by recommends no

10 CFR 50.49 EQ intrusion of borated further evaluation.

requirements that water (See Section -

are exposed to 3.6.2.1)

borated water

leakage

Item Number

3.6.1-5 - -i

The staff's review of the applicant's electrical components followed one of several approaches.

One approach, documented in Section 3.6.2.1, involved the staff's'review of the AMR results for

components in the electrical and l&C components that the applicant indicated are consistent

with the GALL Report and do not require further evaluation. Another approach, documented in

Section 3.6.2.2, involved the staff's review of the AMR results for components in the electrical

and I&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,

involved the staff's review of the AMR results' for c6m ponents in 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. The staff d6cumerited its review of AMPs that are credited tomanage'or monitor aging effects of the el6ctrical components and component groups in Section

3.0.3 of this SER.

The'applicant credited four AMPs to manage the aging effects associated with electrical and

I&C components. Three of these AMPs are credited to manage aging for components in other

system groups (common AMPs), while the other AMP is credited with managing only electrical

and l&C components. The AMPs include the f6llowing:

* Inservice Inspection Program

* External Surface Monitoring Program

* Buried Piping and Tank Inspection Program

* Non-EQ Cables Program

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3.6.2.1 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Not Recommended

Summary of Technical Information in the ApDlication

In Section 3.6.2.1.1 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 components:

* Non-EQ Cables Program

* External Surfaces Monitoring Program

* Buried Piping and Tank Inspection Program

The applicant credited the Non-EQ Cables Program (Appendix B.5.6) to manage aging effects

of all electrical components within the license renewal scope which have AERMs. This

program for cables and connections includes adverse environment inspection and walkdown for

non-EQ cables, as well as pull box inspections and water elimination activities for mediumvoltage potentially submerged cables. It also includes special tests for certain neutron

monitoring instrumentation cables. The applicant claimed that the combined AMP is consistent

with GALL AMP XL.E1, "Cables and Connections Not Subject to 10 CFR 50.49 EQ

Requirements," and GALL AMP XL.E3, "Inaccessible Medium-Voltage Cables Not Subject to

10 CFR 50.49 EQ Requirements." The applicant indicated that the AMP for electrical cables

used in instrumentation circuits not subject to 10 CFR 50.49, and which are sensitive to a

reduction in conductor insulation resistance, is consistent with GALL AMP XL.E2, with an

exception.

Staff Evaluation

In Table 3.6.2-1 of the LRA, the applicant summarized the AMRs for the electrical components

and identified which AMRs it considered to be consistent with the GALL Report.

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 GALL. Therefore, the staff finds,

that the applicant identified all applicable aging effects that are appropriate for the materialenvironment combinations listed.

On the basis of its audit and review, the staff concludes that the applicant has demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

Conclusion

The staff has evaluated the applicant's claim of consistency with the GALL Report. The staff

also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. On the basis of its review,

the staff finds that the applicant has demonstrated that the effects of aging for these

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components will be adequately rnanaged -so that their intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

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

Is Recommended

Summary of Technical Information in the ADDlication

*For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, 'and f6o whi6h the GALL Report recommends further ~ " - '

evaluation, the staff reviewed the applicant's evhiuation'to determine whether it adequately

addressed these issues. In addition, the staff reviewed the applicant's further evaluations

against the criteria contained in Section 3.6.2.2 of the SRP-LR. The FNP Audit'and Review

Report provides details of the staff's audit and review.

The GALL Report indicates that further eValuatiori'should be performed for the aging effects

described in the following section's of this SER.

Staff Evaluation

3.6.2.2.1 Electrical Equipment Subject to Environment Qualification

As stated in tie!SRP-LR, electrical equiprnmnt'subject to EQ is a TLAA, as defined in'

10 CFR 54.3, and TLAAs must be evaluated in accordance with'10 CFR 54.21(c)(1). -The staff

documented its review of the applicani's evaluation of this TLAA'in Section 4.4 of this SER.'. In

performing this review, the staff followed the guidance in Section 4.4 of the SRP-LR.

Conclusion'- '-

The staff has' evaluated the applicant's clairri of consistency with the GALL Report. The staff -

also review'ed information'pertaining to the applicant's consideration of recent operating

experience and proposals for managing'associated aging effects. On the basis of its review,

the staff finds that the applicant has demonstrated that the effects of aging for these

components will be adequately managed, so that their intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). -

3.6.2.3 AMR Results That Are Not Consistent With or Not Addressed in the GALL Report

In Table 3.6.2-1 of the LRA, the applicant summarized the AMRs for the plantwide electrical

system components and identified those AMRs it considered not to be con sistent with the GALL

Report.

This portion of the staff re'view involved the AMR results that are not consistent with or notaddressed in the'GALL Report. In its LRA,'the applicant did not'address the AMR results of the

electrical components which are not addressed in the GALL Report. During the staff's audit of

the FNP License Renewal Program from November 3 - 7, 2003, the staff asked the applicant to

address the AMR results for these electrical components and justify why AMPs are not

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required. The applicant responded to the staff's request in its letter dated December 5, 2003

(SNC Letter No. NL-03-2418).

3.6.2.3.1 Electrical Connectors Not Subject to 10 CFR 50.49 EQ Requirements That Are

Exposed to Borated Water Leakage

Summary of Technical Information in the Application

Aging Effects

In LRA Section 3.6.2.1.1, the applicant identified the following aging effects associated with

electrical components that require management:

* reduced insulation resistance

* loss of material

The applicant also indicated that it considered a borated water leakage environment for

electrical connectors. However, connectors at FNP, Units 1 and 2, are protected from borated

water leakage by their locations within protective enclosures and by design features which seal

the enclosures along with associated conduit and cable entrances.

Aging Management Program

In LRA Table 3.6.1, the applicant stated that it found that the aging effects for this materialenvironment combination do not require management, and therefore no AMP is required. In

LRA Table 3.6.2-1, the applicant again stated that an AMP is not required.

In LRA Section B.3.5, "Borated Water Leakage Assessment and Evaluation," the applicant

stated that the FNP Borated Water Leakage Assessment and Evaluation Program implements

the plant-specific commitments made in response to GL 88-05, dated May 31, 1988. The FNP

Borated Water Leakage Assessment and Evaluation Program manages loss of material in

areas where there are carbon steel and low-alloy steel structures or components, or electrical

components, onto which borated reactor water might leak.

Staff Evaluation

Aging Effects

The staff agrees that the LRA correctly identified the aging effects associated with electrical

components exposed to boric acid.

Aging Management Program

The staff agrees that an AMP for electrical connections exposed to borated water is not

necessary because the design at FNP inhibits the ingress of borated water into electrical

connections, and the Borated Water Leakage Assessment and Evaluation Program will address

any observed borated water leakage.

The staff finds that the applicant adequately addressed the aging threat to electrical

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connections from borated water by the'designof 'the connection enclosures, supplemented by

its Borated Water Leakage Assessment Program, and that no separate AMP for connectors

exposed to borated water is required.

Conclusion'

On the basi' of its review, the staff finds the'applicant has demonstrated that the effects of

aging will be'adequately managed so that thd'ititended function(s) will be maintained consistent

with the current licensing basis for the period of extended'operation, as required byl 0 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.6.2.3.2 Fuse Holders'

SummarV of Technical Information in the Application

Aging Effects ;u

In LRA Section 3.6.2.1.1, the applicant indicated that it gave the aging effects for fuse holders

special consideration based upon the guidance of ISG:5. The applidant eValuated fuse holders

for the fatigue of rfietal clips- due to mechanical wear-and thermal cycling. The fuse holders

subject to an AMR a're those associated with fuses that are not routinely removed for

rmaintenance'and/or surveillance. When'FNP de-energizes these circuits, power is normally

removed at the safety-related power'supply or by opening links on terminal blocks. Therefore,

FNP does not consider fatigue due to mechanical stress to be an AERM.

The operation of external equipme6nt, such as compr6ssors, fans, and pumps, could induce

vibration infuse holders. Since the useholders'within the scope of thisreview are located in

panels which are seismically mounted on their own support structure, separate from sources of

vibration, FNP d6es-not consider vibration to be an applicable aging mechanism. -

Corrosion of metallic clamnps could bccur if the fuse holders were located in humid

environments or exposed to water or boric acid leakage. -The fuse holder panels are'NEMA 12

rated enclosures which protect the fuse holders from external sources of moisture. In addition,

these NEMA 12'enclosures are located inside rooris that protect the panels from the weather,

and no sources of potential mechanical ssteimh leakage-are located in proximity to the panels,

which are not managed for aging. With regard to'internal moisture, a review of plant-specific

operating experience did not reveal any instance of aging as a result of the formation of

condensation internal to the panels. Based upon recent inspections of the fuse blocks, the

surface condition of the fuse clips shows no signs of corrosion. Additionally, there is no sign of

moisture.

Aging Management Prog'ram ' ' ' '- .

In LRA Section 3.6.2.1.1, the applicant concluded that it had not identified any AERMs for inscope fuse holders.

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In Table 3.6.2-1, the applicant again stated that an AMP was not required.

Staff Evaluation

In a letter dated March 10, 2003, the NRC forwarded to the NEI and the Union of Concerned

Scientists the ISG on the screening of electrical fuse holders. The staff position indicated that

fuse holders should be scoped, screened, and included in the AMR in the same manner as

terminal blocks and other types of electrical connections that are currently being treated in the

process. This position only applies to fuse holders that are not part of a larger assembly such

as switchgear, power supplies, power inverters, battery chargers, or circuit boards. Fuse

holders in these types of active components would be considered as a part of the larger

assembly and not subject to an AMR.

Aging Effects

Operating experience, as discussed in NUREG-1760, "Aging Assessment of Safety-Related

Fuses Used in Low- and Medium-Voltage Applications in Nuclear Power Plants," issued May

2002, identified that aging stressors such as vibration, thermal cycling, electrical transients,

mechanical stress, fatigue, corrosion, chemical contamination, or oxidation of the connection

surfaces can result in fuse holder failure. The staff documented its final position on this issue in

ISG-5.

Section 3.6.2.1.1 of the FNP LRA indicates that the AMR of fuse holders addressed fatigue

from mechanical wear and thermal cycling and concluded that fatigue due to mechanical stress

is not considered an AERM because the fuses are not routinely removed for maintenance or

surveillance activities. The discussion contained in its original LRA, Section 3.6.2.1.1, did not

mention the results of the thermal cycling review, nor did it address the other stressors covered

in NUREG-1760.

By letter dated December 5i 2003 (SNC Letter No. NL-03-241,8), the applicant supplemented its

LRA, Section 3.6.2.1.1, by addressing the thermal cycling review and the remaining aging

stressors not initially described in the LRA. The applicant stated that for fuse holders, it

evaluated aging effects due to. ambient thermal stress, radiation, general corrosion, boric acid

corrosion, vibration and self-loosening of hardware, mechanical stress (fatigue), electrical

transients, and thermal cycling. The applicant did not identify any AERMs. The scope of GALL

AMP XL.E1 includes fuse holders, similar to other cable connectors and terminations.

The staff agreed that the LRA, together with the supplemental information provided by the

applicant in its letter dated December 5, 2003 (SNC Letter No. NL-03-2418), correctly identified

the aging effects associated with fuse holders.

Aging Management Program

The staff agrees that no AMP for fuse holders is required.

The staff finds that the applicant adequately addressed the aging threat to fuse holders and that

ISG-5 is satisfied, no separate AMP for separately mounted fuse holders is required.

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Conclusion -

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by-10 CFR

54.21 (a)(3). -

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in:

these components, as required by 10 CFR 54.21 (d).

3.6.2.3.3 High-Voltage Insulators --.

Summary of Technical Information in the ADplication

Aging Effects

Table 2.5.1 of the LRA identifies high-voltage insulators as a component within the scope of

license renewal.

In LRA Section 3.6.2.1.1, the applicant listed the following AERMs associated with electrical

components:

* reduced insulation resistance

* loss of material

However, the applicant did not address high-voltage insulators in LRA Section 3.6.2.1.1. In

Table 3.6.2-1, the applicant stated that an AMP is not required for high-voltage insulators

because there is no AERM.

Aging Management Program

In LRA Table 3.6.2-1, the applicant stated that there are no AERMs for high-voltage insulators.

Staff Evaluation

Aging Effects

Various airbome materials, such as dust, salt, and industrial effluents, can contaminate

insulator surfaces. A large buildup of contamination enables the conductor voltage to track

along the surface more easily and can lead to insulator flashover. Surface contamination can

be a problem in areas where a greater concentration of airborne particles is prevalent. Cracks

have been known to occur in insulators when the cement that binds the parts together expands

enough to crack the porcelain. Mechanical wear is another-aging effect for strain and

suspension insulators because they are subject to movement. Wind blowing the supported

transmission conductor, causing it to swing from side to side, can cause movement of

insulators. If this swinging is frequent enough, it could cause wear in the metal contact points

of the insulator string and between an insulator and the supporting hardware. During its audit,

the staff requested the applicant to address insulator surface cracking.

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In its letter dated December 5, 2003 (SNC Letter No. NL-03-241 8), the applicant satisfactorily

addressed this concern by stating that no airborne contaminents exist in the area around FNP,

Units 1 and 2, that rain would not wash away. The applicant also stated that the type of

insulators used at FNP are not subject to the cement growth cracking failure mechanism seen

on other types of insulators, and operating experience has shown that the strain insulator

components are designed with a sufficient strength margin to prevent cracking failures due to

tension. In addition, the transmission conductors within the scope of license renewal at FNP

are short spans located entirely within the high-voltage switchyard and therefore exert less

tension than normally found for a transmission line. Therefore, cracking is not an AERM for

FNP.

The staff agrees that the LRA, together with the supplemental information in its letter dated

December 5, 2003 (SNC Letter No. NL-03-241 8), correctly identified the aging effects

associated with high-voltage insulators.

Aging Management Program

The staff agrees that no AMP for high-voltage insulators is required.

The staff finds that the applicant adequately addressed the aging threat to high-voltage

insulators and that it correctly concluded that no separate AMP for high-voltage insulators is

required.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.6.2.3.4 Metal-Enclosed Cable Bus

Summary of Technical Information in the Application

Aging Effects

Table 2.5.1 of the LRA identifies the metal-enclosed cable bus as a component within the scope

of license renewal.

In LRA Section 3.6.2.1.1, the applicant listed the following AERMs associated with electrical

components:

reduced insulation resistance

loss of material

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However, the applicant did not address the metal-'enclosed cable bus in Section 3.6.2.1.1.

Aging Management Program. '

In LRA Table 3.6.2-1 the applicant stated that no AERMs exist for the metal-enclosed cable

bus.

Table 3.6.1 'of the LRA states that Appendix 8.5.6, "Non-EQ Cable'Program," includes the,

insulated cable portion of the metal-en6losed cable bus.'

In its letter dated December 5, 2003 (SNC Letter No.ANL-03-2418),;the applicant stated that it

performed an AMR and concluded that an AMP is not required because the bus has no

AERMs. The applicant's response did not provide any details.

Staff Evaluation .r

Aging Effects '

In its' letter dated April 22, 2004 (SNC Letter'N6.' NL-04-0678), the applicant described the cable

bus configuration utilized at FNP as insulated cable in a vented tray traversing from startup,

auxiliary transformers to switchgear locatioris. 'Cable splices are made in tap boxes, which

contain aluminum channel conductors mounted on insulators. Cable conductors are equipped

with connectors which are bolted to the channel conductors.

The nonsegregated phase bus ducts are constructed of the following materials:

* aliiminigm'-'; - - - -: .

0

0

0

0

galvanized steel I -

stainless steel'-

porcelain

various organic polymers

fiberglass

I .

1. iI

The nonsegregated phase bus ducts are exposed to' both inside and outside environments.

An inside environment is associated with components that are found within environmentally

controlled structures. 'At a minimum: temperature is controlled to prevent freezing: This

'environment Would include'the auxiliary and turbine buildings forethe metal-enclosed cable bus. . . s - - . : . - ;, .i, , . ,. : . . .- . :

Inr'an'outside' environment, components may be 6 ip6ged to direct sunlight, precipitation, and

freezing conditions. The GALL Report calls this environment weather exposed, and for the

metal-enclosed cable bus it would includ6the low-voltage switchyard.

Aging effects for the nonsegregated phase bus ducts requiring evaluation are those associated

with insulation material deterioration due to aging,nmoisture/debris intrusion, and bolt loosening

due to thermal cycling.

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Insulation Material Deterioration Due to Aging

The cable bus ducts are located both inside and outside. The metal bus duct enclosures

protect the enclosed insulated cables from weather. The bus cables exit the bus duct

enclosures in the low-voltage switchyard, and approximately 6 feet of the cables are exposed

where they connect to the startup auxiliary transformers. The exposed cable insulation is

ethylene propylene rubber (EPR) with a Hypalon (chlorosulfonated polyethylene) jacket,

discussed in SAND 96-0344, "Aging Management Guideline for Commercial Nuclear Power

Plants-Electrical Cable and Terminations," issued September 1996. The cables have no

significant aging effects when exposed to these conditions. Therefore, insulation material

deterioration due to aging is not an AERM.

Moisture/Debris Intrusion

The cable bus duct enclosures are constructed of sheet aluminum attached to an aluminum

angle frame with both welded and bolted connections. The side panels are louvered. Bus duct

enclosures are located both inside and outside. Tap boxes are constructed similar to bus duct

enclosures, except with solid covers. All tap boxes for in-scope cable bus ducts are located

inside. Moisture and debris could enter the cable bus.duct through the louvered side panels.

However, this has no adverse effect on the insulated cable conductors. The solid cover design

precludes the entry of moisture and debris into the tap boxes. Therefore, moisture/debris

intrusion is not an AERM.

Bolt Loosening Due to Thermal Cycling

Industry experience has shown that bus ducts exposed to appreciable ohmic or ambient heating

during operation may experience loosening of bolted connections related to the repeated

cycling of connected loads or the ambient temperature environment. This phenomenon can

occur in heavily loaded circuits (i.e., those exposed to appreciable ohmic or ambient heating)

that are routinely cycled.

The cable bus duct was designed for a hottest spot temperature rise of 35 OC above 40 OC.

This results in a temperature of 75 0

C (167 OF). The cables contained in the cable bus duct are

insulated with EPR insulation. Per Table 9.1 in the 'EPRI License Renewal Electrical

Handbook TR-1003057 Final Report," issued December 2001, 167 0F equates to a 60-year life.

The portions of the metal-enclosed cable bus duct within the scope of license renewal are?-.

normally energized. Thus, routine cycling is not experienced. Connections from the bus to the

equipment are made with Belleville washers, which are superior to split washers in maintaining

compression force on the connections. The FNP nonsegregated phase bus ducts are designed

to carry the output of the startup auxiliary transformers. The worst-case loading on any portion

of the cable bus duct for either unit is approximately 65 percent. Therefore, bolt loosening due

to thermal cycling is not an AERM.

A review of plant operating experience at FNP did not reveal any issues associated with the

cable bus duct.

The applicant reviewed industry operating experience for problems associated with bus ducts

and selected the following items for further review and disposition:

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Information Notice 89-64, "Electrical Bus Bar Failures," was issued to address Noryl Insulated

medium voltage bus bar failures that occurred at several nuclear facilities. The failures identified

in Information Notice 89-64 were attributed to cracking of the Noryl bus bar insulation in,

combination with the accumulation of rmoisture dr debris in the bus duct housings that provided a

tracking path to ground. Noryl is the General Electric'Trademark name foraplastlctypeelectrical'

insulation material.

Information Notice 98-36, Inadequate or Poorly Controlled, Non-Safety Related Maintenance

Activities Unnecessarily Challenged Safety Systems," notified licensees of various inadequate'-

maintenance activities (e.g., failure to Install gaskets or caulking of outdoor components) in the

industry which resulted in moisture intrusion and challenges to safety related systems.

- Information Notice 2000-14, Non-Vital Bus Fault Leads to Fire and Loss of Offsite Power,".

Informed licensees of a transient at Diablo Canyon nuclear plant caused by a failure of a bus bar

due to overheating at a splice joint. Potential causes of the failure include inconsistent silver

plating of aluminum bus bars, currents approaching bus capacity, undersized splice plates, torque

relaxation of connecting bolts, and undetected damage from a 1995 explosion of Auxiliary

Transformer 1-1. - ,

The nonsegregated phase bus duct is chaiacterized as all three'phases contained in a-single

enclosure, such as exposed conductors (i.e., tube, bar, channel) insulated from the enclosure,

or insulated cable. For its bus duct configuration, FNP utilizes insulated cable in a vented tray

traversing from startup auxiliary transformers to switchgear. The problems documented in INs

89-64, 98-36, and 2000-14 apply to bus ducts with exposed bar condu6tors. The failure

mechanisms identified in INs 89-64 and 98-36'do not apply to FNP because FNP bus ducts do

not have exposed conductors.

Some of the potential causes of the bus bar failure addressed in IN 2000-14 could apply to

other types of bus duct designs. These mechanisms include currents approaching bus capacity

and torque relaxation of connecting bolts. The FNP nonsegregated phase bus'ducts are

designed to carry the output of the startup auxiliary transformers. The worst-case loading'on

any portion of the cable bus duct for either unit is approximately 65 percent. 'Connections from

the bus to the equipment are made with BelleviIle washers, which are superior to split washers

in maintaining compression force on the connections. Therefore, currents approaching bus

capacity and torque relaxation are not applicable-aging m'echanisms for the nonsegregated

phase bus ducts at FNP.

The staff agrees that the LRA, together with the supplemental information in its letter dated

April 22, 2004 (SNC Letter No. NL-04-0678), correctly identified 'the aging effects associated

with the metal-enclosed (nonsegregated phase) cable bus.

Aging Management Program

In its letter dated April 22, 2004 (SNC Letter No. NL-04-0678),;the applicant concluded that

none of the aging effects evaluated for nonsegregated phase bus ducts require management.

Although the AMR concluded th6re 'were no AERMs, the Non-EQ Cables Program includes

nonsegregated phase bus duct cables, as noted in the discussion column for Item 3.6.1-2 in

LRA Table 3.6.1. In its letter dated July 9,2004 (SNC Letter No. NL-04-121 8), the applicant

stated that it will visually inspect the portion of the bus cables that exit the bus duct enclosure in

the low-voltage switchyard, where the cables are' ex`posed f6r approximately 6 feet, as part of

the Non-EQ Cables Program.

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The staff agrees that no AMP for the metal-enclosed cable bus is required.

The staff concludes that the applicant adequately addressed the aging threat to the metalenclosed cable bus and correctly concluded that no separate AMP for the metal-enclosed cable

bus is required.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21(d).

3.6.2.3.5 Oil-Static Cable

Section 8.2, 'Offsite Power System," of the FNP FSAR describes the oil-static cable system.

The 230-kV switchyard is interconnected to the onsite electrical distribution system by four

physically separated underground oil-static cables.- Each cable supplies power to one of the

four startup auxiliary transformers which supply power to the emergency buses for FNP, Units 1

and 2. Each of the four underground cable circuits consists of three single-conductor 500-MCM

compact round aluminum conductors. Each conductor has 0.760 inches of paper insulation,

zinc alloy shielding tape, and a 0.0063-inch by 188-inch zinc alloy skid wire. Metalized paper

tape is provided adjacent to the conductor and also over the insulating paper tapes. The three

single-conductor cables of each circuit are contained in a 6 5/8-inch O.D. by 0.250-inch wall

somastic-coated pipe.

Summary of Technical Information in the Application

Aging Effects

In Section 3.6.2.1.1 of the LRA, the applicant indicated that the'portion of the oil-static cable

system that contains electrical conductors is both buried and outside. The pumps and piping

associated with the oil-static cable pressurization system (LRA Section 2.3.3.20) are inside and

buried. The interior environment for all portions of the oil-static cable system is lube oil.

Table 3.6.2-1 of the LRA lists the intended functions for the oil-static cable as pressure

boundary, as well as providirig electrical connections. The aging effect for the pressure

boundary function is loss of material. The electrical connection function had no aging effect.

Aging Management Program

Appendix B.5.3, "External Surfaces Monitoring Program," to the LRA states that the applicant'

credited the FNP External Su'rfaces Monitoring Program with managing the loss of'material in

the external surfaces of specific component/commodity groups in the'oil-static cable -

pressurization system. It also states that the applicant credited the FNP External Surfaces

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Monitoring Program with managing the loss of material, cracking, and change in material.

properties in elastomer flexible hoses used in the oil-static cable pressurization system.

Appendix B.5.4, "Buried Piping and Tank Inspection Program," to the LRA states that the scope

of the FNP Buried Piping and Tank Inspection Program includes the external surfaces of the oilstatic cable pressurization system's buried components from the high-voltage to the low-voltage

switchyard.

In SNC Letter No. NL-04-0384, dated March 31, 2004, the applicant stated that the External

Surfaces Monitoring Program will manage aging for the pressure boundary function for the

portion of the oil-static cables that are above the ground. The Buried Piping and Tank

Inspection Program will manage aging for the pressure boundary function of the portion of the

oil-static cables that is buried.. The boundary, change is located where the oil supply pipe

connects to the oil-static cables.

Staff Evaluation

Aging Effects

In its letter dated March 31, 2004 (SNC Letter No. NL-04-0384), the applicant stated that it

identified no AERMs for the oil-static cable insulation system. Table 3.6.2-1 (page 3.6-11)

should not have a horizontal grid line dividing the component type "oil-static cables" from the

intended function of providing electrical connections. In addition, the applicant inadvertently

omitted the component material of paper, but the AMR for oil-static cables has addressed this..

The applicant reviewed operating experience by searching the FNP condition reports database

and by interviewing knowledgeable personnel, both within the Southern Electric System as well

as industry consultants. The applicant did not identify any cases where a failure of the oilimpregnated paper insulation system occurred.

The oil-static cables are attached to vendor-supplied terminals inside potheads at the cable

ends. The other end of the terminals protrude through the potheads where the vendor-supplied

lugs are attached in order to make connections to switchyard conductors. The component type

uswitchyard bus" includes the connections between the oil-static cables and the conductors in

the high- and low-voltage switchyards.

The staff agrees that the LRA, together-with the supplemental information provided in its letter

dated March 31, 2004 (SNC Letter No. NL-04-0384), correctly identifies the aging effects

associated with the oil-static cable.

Aging Management Program

The staff agrees that no AMP for the electrical connection function of the oil-static cables is

required. The staff also agrees that the External Surfaces Monitoring Program should manage

age for the pressure boundary function of the portion of the oil-static cables that ire above the

ground. The Buried Piping and Tank inspection Program should, manage age for the pressure

boundary function of the portion of the oil-static cables that are buried.

The staff finds that the applicant adequately addressed the aging threat to oil-static cables and

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that it correctly concluded that no separate AMP for the electrical connection function of the oilstatic cables is required. The staff also finds that the applicant correctly assigned the pressure

boundary function of the oil-static cables and the oil-static cable pressurization systems to the

External Surfaces Monitoring Program and the Buried Piping and Tank Inspection Program.

Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.6.2.3.6 Switchyard Bus

Summary of Technical Information in the ApDlication

Aging Effects

Table 2.5.1 of the LRA identifies the switchyard bus as a component within the scope of license

renewal.

In LRA Section 3.6.2.1.1, the applicant listed the following AERM associated with electrical

components:

* loss of material

However, the applicant did not address the switchyard bus in LRA Section 3.6.2.1.1. In Table

3.6.2-1, the applicant stated that an AMP is not required for the switchyard bus because there is

no AERM.

Aging Management Program

In Table 3.6.2-1, the applicant stated that there are no AERMs for the switchyard bus.

Staff Evaluation

Aging Effects

The applicant stated that it does not consider the surface oxidation of high-voltage electrical

switchyard bus connections to be a significant aging mechanism at FNP. In its letter dated

December 5, 2063 (SNC Letter No. NL-03-2418), the applicant addressed this concern by

stating that, based on the operating experience at FNP, the surface oxidation did not affect the

function of the conductors and cable accessories. The applicant stated that it coated the

connection surfaces with an antioxidant compound before tightening the connection. The staff

requested confirmation that the antioxidant compound was stable through the period of

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operation.

In its letter-dated March 22, 2004, via`RAI 3.6.2-3, the staff questioned the aging effect of

surface oxidation of the high-voltage switchyard bus connections. The applicant responded in

its letter dated April 22, 2004 (SNC Letter No. NL-04-0678) that the antioxidant compound is a

consumable which is used for initial assembly of connections and replaced as required when

connections are taken apart and reassembled (e.g., during routine maintenance). The

applicant also stated that the antioxidant compound has proven to be stable through many

years of serVice at FNP' The applicant further stated that operating experience confirms that

FNP has had no failures'6f connections caused by degradation of the compound.. The staff

agrees that no aging effects apply to the high-voltage switchyard bus and connections.

Aging Management Program

The staff agreed that no AMP for the high-voltage switchyard bus is required.

The staff finds that the applicant adequately addressed the aging threat to the high-voltage

switchyard bus and that it correctly concluded that no separate AMP for the high-voltageswitchyard bus is required.

Conclusion

On the basis of its review,' the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation; as' required by 10 CFR

54.21 (a)(3). - -' -

The staff also reviewed the applicable.FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.6.2.3.7 Transmission Conductors

Summary of Technical Information in the Application

Aging Effects '. -v. -

Table 2.5.1 of the LRA identifies transmission conductors as a component within the scope of

license renewal.

In LRA Section 3.6.2.1.1, the applicant listed the following AERM associated with electrical

components IJI - - - -

* loss of material

However, the applicant did not address transmission conductors in LRA Section 3.6.2.1.1. In

Table 3.6.2-1, the applicant stated that an AMP is not required for transmission conductors

because there is no AERM.

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Aging Management Program

In Table 3.6.2-1, the applicant stated that there are no AERMs for transmission conductors.

Staff Evaluation

Aging Effects

The most prevalent mechanism contributing to the loss of high-voltage transmission conductor

strength is corrosion, which includes corrosion of the steel core and aluminum strand pitting. In

its letter dated December 5,,2004 (SNC Letter No. NL-03-2418), the applicant addressed the

loss of strength caused by aging by referring to an Ontario-Hydro corrosion test which

demonstrated satisfactory strength in an 80-year old aluminum cable-steel reinforced (ACSR)

conductor. In RAI 3.6.2-4, by letter dated March 22, 2004, the staff requested confirmation that

the conductors in use at FNP are identical to those tested by Ontario-Hydro.. If not, the -

applicant should evaluate the differences. The staff also requested that the applicant indicate

the useful life of the transmission conductors and their accessories, such as line terminal

connectors and line splices used at FNP.

In its letter dated April 22, 2004 (SNC Letter No. NL-04-0678), the applicant responded that the

ACSR conductors tested by Ontario-Hydro are representative of the overhead conductors used

at FNP, and that these conductors are constructed of aluminum strands with a stranded

galvanized steel reinforced center. The applicant stated that it had not determined an exact

match between the conductor size and stranding for every cable used in the high-voltage

switchyard at FNP and those tested by Ontario-Hydro. In its letter dated June 25, 2004 (SNC

Letter No. NL-04-1096), the applicant compared the strength of the minimum-size transmission

conductor used at FNP with the results of the material loss found by the Ontario-Hydro tests

and concluded that sufficient margin would remain during the period of extended operation.

The applicant stated that the transmission conductor accessories, such as line terminal

connectors and line splices, are made from aluminum or galvanized steel. There are no

organic components to restrict the useful life of the accessories. The useful life of aluminum

and galvanized steel materials in transmission system service are consistent with or greater

than the ACSR conductors.

The applicant stated that the spans in the high-voltage switchyard are much less than those in a

typical transmission line. Therefore, the tension exerted on the conductors and accessories is

less than would be experienced in typical applications.

Aging Management Program

The staff agrees with the applicant's conclusion that no AMP for transmission conductors is

required.

The staff concludes that the applicant adequately addressed the aging effects on the

transmission conductors and correctly concluded that no separate AMP for transmission

conductors is required.

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Conclusion

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately mariaged so that the intended function(s) will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in

these components, as required by 10 CFR 54.21 (d).

3.6.3 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that the

aging effects associated with the electrical components will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable FSAR Supplement program summaries and concludes

that the FSAR Supplement adequately describes the AMPs credited for managing aging in the

electrical components, as required by 10 CFR 54.21(d).

3.7 Conclusion for Aging Management

The staff has reviewed the information in Section 3, "Aging Management Review Results," and

Appendix B, "Aging Management Programs and Activities" of the LRA. On the basis of its

review of the AMR results and AMPs, the staff concludes that the applicant has demonstrated

that the aging effects will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the applicable FSAR Supplement program

summaries and concludes that the FSAR Supplement adequately describes the AMPs credited

for managing aging, as required by 10 CFR 54.21 (d).

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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). Southern

Nuclear Operating Company, Inc. (SNC or the applicant) discusses the TLAAs in Sections 4.2

through 4.5 of its license renewal application (LRA). Sections 4.2 through 4.5 of this safety

evaluation report (SER) documents the review of the TLAAs conducted by the staff of the U.S.

Nuclear Regulatory Commission (NRC) (thestaff).-

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)(i)), 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), anr applicant must provide a list of plant-specific")

exemptions granted under 10 CFR 50.12 that are based on TLAAs. For any such exemptions,

the applicant must pr6vide'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

To identify the TLAAs, the applicant evaluated calculations for the Joseph M. Farley Nuclear

Plant (FNP), Units 1 and 2, against the'six criteria specified in 10 CFR 54.3. The applicant

indicated that it had identified the calculations which met the six criteria by searching the current

licensing basis (CLB). The CLB includes-th6 final safety analysis report (FSAR) and docketed

correspondence. The applicant also reviewed design calculations-performed by Bechtel Power

Corporation (the previous architect engineer), theSouthem Company Services, Inc. (SCS)

engineering organization (the current architect engineer), and the Westinghouse Electric

Company (W) for the nuclear steam supply system equipment scope. The applicant listed the

following applicable TLAAs in Table 4.1.2,' Potential Time-Limited Aging Analysis," of the LRA:

* r reactor vessel neutron embrittlermienit

* concrete containi entftendon prestr'ess

* - .- metal fatigue '.

* environmental qualification of electrical equipment

* high-energy line br6ak postulation based on fatigue cumulative usage factor'

* low-temperature overpressure protection (LTOP) analyses

* fatigue analysis of the reactor coolant pump flywheel

* leak before break

residual heat removal safety relief valve flow capacity verifications for cold overpressure mitigatio'n'analysis ' * -- -fatigue of reactor vessel supports - P ; - -

* ' silting of the ultimate heat sink

Pursuant to 10 CFR 54.21 (c)(2), the applicant stated that it did not identify any exemptions

granted under 10 CFR 50.12 that were based on a TLAA, as defined in 10 CFR 54.3.

4-1
4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant identified the TLAAs applicable to FNP, Units 1 and 2, and

discussed exemptions based on these 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).

As defined in 10 CFR 54.3, TLAAs are 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 (i.e., 40 years)

(4) are determined to be relevant by the applicant in making a safety determination

(5) involve conclusions, or provide the basis for conclusions, related to the capability of the

system, structure, and component to perform its intended functions, as delineated in

10 CFR 54.4(b)

(6) are contained or incorporated by reference in the current licensing basis

The applicant provided a list of common TLAAs from NUREG-1800, "Standard Review Plan for

Review of License Renewal'Applications for Nuclear Power Plant," dated July 2001. The

applicant listed those TLAAs that are applicable to FNP, Units 1 and 2, in Table 4.1.2, Potential

Time-Limited Aging Analysis, of the LRA.

As required by 10 CFR 54.21 (c)(2), an applicant must provide a list of all ekemptions'grahted

under 10 CFR 50.12 which' are determined to be based on a TLAA and which are evaluated

and justified for continuation' through the period of extended operation. In its LRA, the applicant

stated that it performed a search of the FNP docketed correspond6nrce, the operating licenses,

and the FSAR, and evaluated each exemption in effect for TLAA applicability. The applicant did

not identify any TLAA-based exemptions. On the basis of the informatiori provided by the

applicant with regard to the process used to identify TLAA-based exemptions, as well as the

results of the applicant's search, the staff finds that the applicant identified no TLAA-based

exemptions which are justified for continuation through the period of extended operation, in

accordance with 10 CFR 54.21 (c)(2).

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), and has confirmed that no exemptions to

10 CFR 50.12 have been granted on the basis of a TLAA, as required by 10 CFR 54.21 (c)(2).

4-2
4.2 Reactor Ve'ssel Neutron Embrittlement

The applicant's design contains TLAAs that address the effects of neutron irradiation

embrittlement of the reactor vessels (RVs)'for both units. The calculations have been updated

to address the'additional 20 years of operation, for which 54 effective full-power years (EFPYs)

are sufficient to cover the current and extended operating term. These calculations include (1)

the peak fluence values used to determine the limiting RV beltline materials, (2) the Charpy

upper-shelf energy (USE) and the reference temperature for pressurized thermal shock (RTpTs),

(3) the pressure and temperature (P-T) operating limit curves, and (4) the adjusted reference

temperatures (ART).

4.2.1' Neutron Fluence

4.2.1.1 Summary of Technical Information in the Application - -

The applicant calculated neutron fluences using a discrete-ordinates transport method,

satisfying the requirements set forth in Regulatory Guide (RG) 1.190, "Calculational and

Dosimetry Methods for Determining Pressure Vessel Neutron Fluence," dated March 2001.

The updated calculations show that the margins required in Appendix G will be maintained,

even after 54 EFPYs of operation. The applicant provided the following table which -

summarizes the peak fluence values for FNP-Units 1 and 2 associated with 54 EFPYs of

operation. '

| --- O Fluenice ; i- ;;' '' 45- Fluence - -' |

Surface 1/4T | 3/4T Sur-face | -1/4T '- 3/4T l

:-:- - ~ :FNP - . Unit 1 -(54 EFPY): ,

-64 | 4.00 | 1.55 -|,2-01 .5''|: 0.487

FNP Unit 2 (54 EFPY) '

6.29 3.92 1.52 2.04 1.27 0.494 - ...... .- , ... ..... ,;,1 

Note: All fluence values are in units of 1019 ircm2E >1 MeV. -' -

42. 1.2 Staff Evaluation :

RG 1.190 provides guidancd regarding acceptable mnethodsfor the befichmarking of vessel

fluence methiodologies based on th& erirem ntsof General Design Criterion (GDC) 31,'

"Fracture Preventioh of Rea'ctorCoolant Pressubre Bo6undary," and, in part, on GDC 14,

"Reactor Coolant Pressure Boundary;" and GDC 30, Quality of Reactor Coolant Pressure

Boundary." Therefore, the staff based its review of the peak vessel fluence evaluation for FNP,

Units 1 and 2, on the adherence of the calculational method to the guidance in RG 1 1.90.

The staff's review of WCAP-14687, "Joseph M. Farley Units 1 and 2, Radiation Analysis and

Neutron Dosirnietry Evaluation," dated Juine 1996, indicates that this is the surveillance capsule

analysis report for FNP, Unit 1, Capsule W, which'was removed at the end of cycle'12. The

4-3
I

fluence values from WCAP-14687 that the applicant cited in the FNP, Unit 1, LRA for 32 and 54

EFPYs were calculated in accordance with the guidance in RG 1.190. The calculated 54-

EFPY-fluence values from WCAP-1 4687- are therefore acceptable for use by the applicant. The

staff confirmed that the 54-EFPY-fluence values cited in WCAP-1 4687 were the same 54- -

EFPY-fluence values for FNP, Unit 1, that the applicant cited in Section 4.2.1 and Table 4.2.1 of

the FNP LRA.

The staff's review of WCAP-15171, "Analysis of Capsule Z from the Alabama Power Company,

Joseph M. Farley Nuclear Plant, Unit 2, Reactor Vessel Radiation Surveillance Program," dated

February 1999, indicates that this is the surveillance capsule report for Capsule Z from FNP,

Unit 2. The report meets the guidance in RG 1.190. The fluence values in WCAP-15171 cited

by the applicant were calculated in accordance with the guidance in RG 1.190 for 54 EFPYs of

operation; therefore, the staff considers these values to be acceptable for use by the applicant.

The staff confirmed that the 54-EFPY-fluence values cited in WCAP-1 5171 were the same 54-

EFPY-fluence values for FNP, Unit 2, that the applicant cited in Section 4.2.1 and Table 4.2.1 of

the FNP LRA.

The pressure-temperature limits report (PTLR), issued in 1998, cites WCAP-14040-A, Revision

2, for fluence methodology.' This Westinghouse report was issued before RG 1.190. The

applicant submitted WCAP-1 6221 (which contains the latest surveillance capsule analysis) to

demonstrate the application of the methodology (Ref. 2). During a conference call held on May

26, 2004, the applicant agreed to update the methodology references in the FNP PTLR. By

letter dated June-4,2004 (SNC Letter No. NL-04-0933), the applicant provided its supplemental

information concerning reactor vessel beltline neutron flu6nce Values applicable to a postulated

20-year license renewal period. The applicant restated that the fluence calculation conforms to

the guidance in RG 1.190.

The staff reviewed the submitted information and agrees that the fluence calculational

methodology complies with the guidance in RG 1.190, and is, therefore, acceptable. Values of

vessel fluence calculated in this manner are acceptable for application to pressurized thermal

shock (PTS) (10 CFR 50.61), to pressure temperature limits to satisfy the requirements of

Appendices G and H to 10 CFR Part 50, and for the calculation of the USE.

The applicant used the peak clad-to-base metal interface fluence values from References 1 and

2 in the adjusted reference temperature (RTpTs) value calculations for the FNP PTS

assessments. The staff evaluated the PTS assessments for the extended period of operation

in Section 4.2.3 of this SER. The applicant also used the peak inside surface fluence values to

calculate 1/4T and 3/4T fluence values for both units based on the attenibation formula in RG

1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," dated May 1988. The

staff finds this to be acceptable. The 1/4T and 3/4T neutronr fluences are used in the

calculation of the 1/4T and 3/4T adjusted reference temperatures (1/4T.and 3/4T RTND'T values),

which are inputs to the P-T limits documented in the FNP PTLR. The 1/4T neutron fluence

values are also used as inputs to the USE value assessments. The staff evaluates the TLAAs

for the 54-EFPY 1/4T and 3/4T RTNDT values and the 54-EFPY USE assessments in Sections

4.2.2 and 4.2.4 of this SER, respectively.

WCAP-1 4689, Revision. 6, is the most current licensing basis document citing the 54-EFPY

1/41 and 3/4T neutron fluences for FNP, Units 1 and 2. The 54-EFPY-fluenice values reported

in WCAP-14689, Revision 6, for FNP, Units 1 and 2, are based on acceptable values cited in

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WCAP-14687 and WCAP-15171,:which applied miethodology'cdnsistent with RG 1.190 to

calculate the 54-EFPY-fluence values. Theref6re, the staff con6ludes 'that the 1/4T and 3/4T

fluences for 54 EFPYs reported in WCAP-114689,Rvision 6, are acceptable. The staff

confirmed that the 1/4T and 3/4T fluence valuesfor FNP, Units 1 Md 2, reported in LRA

Section 4.2.1 for 54 EFPYs of operation were the'sarne as the 114T and 3/4T neutron flirence'

values for the units reported in WCAP-1 46899 Ri.-isionh'6'.;

4.2.1.3 FSAR Supplement

As required by 10 CFR 54.21 (d), the FSAR sIpplement for a facility must contain a summary

description of the 'evaluation'of each TLAA proposed fodr the period of extended operation.

The staff determined that Appendix A to the LRA '(FSAR Supplement) did not include a

summary description for the TLAA in LRA S6ction 4.2.1, uNeutron Fluence." The staff

recognizes that the applicant calculated fluencedValues to 54 EFPYs (i e., the end of the

requested license extension).: However, the 'oerating -assumptions in these calculations could

change, for example,'with the introduction of new fuel, 'new material properties, 'etc. In such-an

instance, 10 CFR 50.61 requires recalculation of the fluence and reevaluation of the material

properties.- Because the' applicant had identified the recalculation of the neutron fluence values

as a TLAA for the FNP units, the staff requested that a-corresponding FSAR Supplement

summary description for LRA Section 4.2.1 be included in the FSAR Supplement for the

application. The staff identified this request as RAI 4.2.1.3-1.

In its response to RAI 4.2.1.3-1 (SNC Letter No. NL-04-0617), dated April 16, 2004, the'

applicant provided the following FSAR Supplement summary description for the TLAA on

neutron fluen'c'e calculations: ''-"' ; A.

A.4.1.5 Neutron Fluence Calculation ' 1 2:

SNO updated the reactor vessel neutron embrittlement calculations including'the neutron fluence

calculations for the critical components of the reactor vessel for 54 EFPY in accordance with

10 CFR 54.21(c)(1)(ii). The neutron fluence values that apply for the'current operating conditions

at FNP are summarized in the Pressure and Temperature Limits Report (PTLR) for each unit.

When the PTLR is updated to include P-T limit curves that bound the current level of neutron

embrittlement for the unit, changes In neutron fluence values are included. .. ~ i, - . , , I............

The applicant's response to RAI 4.2.1.3-1 and FSAR Supplement summary description for the

TLAA on neutron fluence calculations indicate that the neutron fluence calculations have been

updated through 54 EFPYs of power operation and will be incorporated into'the PTLR for FNP,

Units 1 and 2. The staff approved the PTLR for. FNl?, Units 1 and 2, in a safety evaluation and

license amendment dated March 31,1998. The PTLR process allows the applicant to

periodically update the P-T limits and the low-temperature overpressure (LTOP) system

setpoints without the need for equesti licnseaendment tothe Technical Specifications

(TS) under the NRC's 10 CFR 50.90 p0'oces.',The PTLR process is based ohn'the NRC's'

approval of a required standard methodologyfr nrthe'generation of the P-T limits aand LTOP'

setpoints. This approach includes the calculational methodology6for periodically updating the'.

neutron fluence valu6s for the bu.nits before the bou'nding neutron fluence values in the current

version 6f the PTLR'are exceeded. Section,4.2.1.2 of this SER demonstrates that th6 applicant

has calculated acceptable liriiitin'g clad-t6-base m'etal'inteface, 1/4T,'and 3/4T neutro-n-fluerice

values for FNP, Units 1 and 2,'through'54 EFPYs:"'WCAP-16221-NP specifies updates to the

;4-5
limiting clad-to-base metal interface, 1/4T, and 3/4T- neutron fluence values for FNP, Unit 1.

This report was docketed for FNP, Unit 1, on April 16, 2004. The report was submitted to meet

the surveillance, data reporting requirements of 10 CFR Part 50, Appendix H, and provided the

Charpy impact data, neutron fluence data, tensile test data, and alloying chemistry data for

FNP, Unit 1, Capsule V, which was, removed from the FNP, Unit 1 RV in the spring of 2003.

This report also updated the 54-EFPY limiting clad-to-base metal interface, 1/4T, and 3/4T

neutron fluence values for the FNP, Unit 1 RV and reassessed all previous surveillance data for

FNP, Unit 1, Capsules Y, U, X, and W.

According to FNP TS 5.6.6; the applicant will be required to incorporate the recent updates to

the limiting 54-EFPY clad-to-base metal interface,. 1/4T, and 3/4T neutron fluence values for

FNP, Unit 1, into the FNP PTLR. The staff concludes that the applicant's FSAR Supplement

summary description for the TLAA on neutron fluence calculations is acceptable because (1)

the applicant is using an acceptable methodology to generate the, limiting clad-to-base metal

interface, 1/4T, and 3/4T neutron fluence values, (2) the applicant's FSAR Supplement

summary description indicates that the neutron fluence values have been updated through 54

EFPYs, and (3) consistent with TS 5.6.6, the applicant will update the PTLR to incorporate the

54-EFPY neutron fluence values and any TLAAs that are dependent on these values before the

P-T limits for 54 EFPYs are required to be implemented.. Therefore, RAI 4.2.1.3-1 is resolved.

The impacts of the updated neutron fluence values for FNP, Unit. 1, on the limiting USE, RTpr5

values, and 1/4T and 3/4T RTNDT values are evaluated in Section 4.2.2.2, 4.2.3.2, and 4.2.4.2 of

this SER, respectively.

4.2.1.4 Conclusion

The staff has reviewed the applicant's TLAA on neutron fluence, as summarized in Section

4.2.1 of the LRA, and has determined that the applicant's calculation of the neutron fluence

values, as projected through the expiration of the extended period of operation for the FNP,

Units 1 and 2, is in conformance with the staff's guidance in RG 1.190. The staff therefore

concludes that the applicant's TLAA for neutron fluence complies with the staff's acceptance

criterion for TLAAs in 10 CFR, 54.21 (c)(1)(ii), and that the safety margins established and

maintained during the current operating term will be maintained during the period of extended

operation, as required by 10 CFR 54.21(c)(1). The staff also concludes that the FSAR

Supplement contains an appropriate summary description of the TLAA on PTS for the period of

extended operation, as required by 10 CFR 54.21 (d).

4.2.2 Upper-Shelf Energy

4.2.2.1 Summary of Technical Information in the Application

Section 4.2.2 of the LRA stated that the RV beltline materials must maintain a Charpy USE of

no less than 50 ft-lb throughout the life of the RV, unless it is demonstrated, in a manner'

approved by the Director, Office of Nuclear Reactor Regulation (NRR), that lower values of

Charpy USE will provide margins of safety against fracture equivalent to those required by'

Appendix G to Section Xl of the American Society of Mechanical Engineers (ASME) Code. The

applicant has projected these analyses to the end of the extended period of operation, in

accordance with the approved methods 'of RG 1.99, Revision 2. The applicant stated the most

limiting Unit 1 locations for USE are the Lower Shell Longitudinal Weld Seams 20-894A and B

4-6
(Heat No. 90099, at the 45' azimuth), which have a projected End of Life (EOL) USE of 52.8 ftlb. For Unit 2, the limiting USE location is Intermediate Shell Plate B7212-1 (on the basis of

surveillance capsule data), which has a projected EOL USE of 58 ft-lb. The LRA included a

summary of the results for the plant's beltline materials.

4.2.2.2 Staff Evaluation

Section IV.A.1 to 10 CFR Part 50, Appendix G, provides the Commission's requirements for

demonstrating that RVs in'U.S. pressurized-water rector (PWR)-type light water reactors will

have ductility throughout their service lives. The 'rul6 requires RV beltline materials to have

USE values equal to or above 75 ft-lb when the materials are in the unirradiated condition, and

equal to or above 50 ft-lb throughout the licensed operating period. RG 1.99, Revision 2,

"Radiation Embrittlement of Reactor Vessel Materials," provides an expanded discussion

regarding the calculations of USE values and describes two methods for determining USE

values for RV beltline materials, depending on whether or not a given RV beltline material is

represented in the plant's Reactor Vessel Material Surveillance Program.

The applicant provided its USE assessments for the RV beltline materials of FNP, Units 1 and

2, in Tables 4.2.2-1 and 4.2.2-2 of the application, respectively.. The USE assessments were

based on the 1/4T neutron fluence values listed in LRA Table 4.2.1. These neutron fluence

values are based on the projected values at the end of the extended period of operation

(i.e., 54 EFPYs).

The staff performed independent calculations of the USE values for the RV beltline materials.

through the expiration of the extended period of operation for FNP, Units 1 and 2. The staff

based its'independent calculations on the 1/4T-neutron fluence values listed in LRA Table 4.2.1

for the FNP RVs: The staff applied the calculational methods in RG 1.99, Revision 2, as its

methodology for performing the independent USE calculations. The staff determined that at

FNP, Unit 1,' Lower Shell Axial Welds 20-984 A and B (Heat No. 90099) are the limiting beltline

materials for USE. -The staff calculated a USE value of 53.1 ft-lb for these welds at 54 EFPYs.

This value is in good agreement with the 54-EFPY, USE value calculated by the applicant for

these welds (i.e., 52.8 ft-lb). Both of these values meet the acceptance criterion in 10 CFR Part

50, Appendix G, for maintaining the USE values of the RV beltline materials above 50 ft-lb

throughout the licensed operating period. The staff confirmed that the recent updates t6 the

surveillance data for FNP, Unit 1, as reported in WCAP-16221 -NP (i.e., the surveillance capsule

report for FNP Unit 1, Capsule V), did not change the limiting USE material and USE value for

FNP, Unit 1..

The staff determined that FNP, Unit 2, Intermediate Shell Plate B7212-1 (Heat No. C7466-1) is

the limiting beltline material for USE. The staff calculated a USE value of 57.9 ft-lb for this plate

at 54 EFPYs. -This value is in good agreement with the 54-EFPY USE value calculated by the

applicant for this material (i.e., 58 ft-lb). Both of these values meet the acceptance criterion in

10 CFR Part 50, Appendix G, for maintaining the USE values of the RV beltline materials above

50 ft-lb throughout the licensed operating period.; -- * ; . s a- . , .- , . se A .- . r -

Based on these assessments, the staff determined that the RVs at FNP, Units 1 and 2,'will

maintain an acceptable level of USE throughout the expiration of the units' extended periods of

operation. The staff therefore concludes that the applicant's TLAA for USE, as given in Section

4.2.2 of the LRA, complies with the requirements of 10 CFR Part 50, Appendix G.

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4.2.2.3 FSAR Supplement

Section A.4.1.1 of the LRA includes the following FSAR Supplement summary description for

the TLAA on USE:

Appendix G of 10 CFR Part 50 requires that the reactor vessel beltline materials must maintain a

Charpy USE of no less than 50 ft-lbs throughout the life of the reactor. SNC has projected the

FNP analyses to the end of the period of extended operation for the limiting component of the

beltline region materials. The limiting Unit 1 location has a projected end-of-life (EOL) USE of 52.8

ft-lbs. For Unit 2, the limiting USE location has a projected EOL USE of 58 ft-lbs. These TLAAs

have been shown to be. acceptable for the period of extended operation in accordance with

10 CFR 54.21 (c)(1)(ii).

The applicant's FSAR Supplement summary description is consistent with the staff analysis for

the TLAA on USE presented in Section 4.2.2.2 of this SER. The FSAR Supplement summary

description summarizes the'applicable USE requirements that'must be met to ensure continued

compliance with 10 CFR Part 50, Appendix G, and demonstrates why the RV beltline materials

at FNP, Units 1 and 2, will be in compliance with the applicable requirements in

10 CFR Part 50, Appendix G, as projected through the expiration of the extended period of

operation for the units. The staff therefore concludes that the FSAR Supplement summary

description for the TLAA on USE is acceptable.

4.2.2.4 Conclusion

The staff has reviewed the applicant's TLAA on USE, as summarized in Section 4.2.2 of the

LRA, and has determined that the RV beitline'materials at FNP, Units.1 and 2, will continue to

comply with the staff's USE requirements detailed in 10 CFR Part 50, Appendix G, throughout

the extended period of operation. The staff therefore concludes that the applicant's TLAA for

USE complies with the staff's acceptance criterion for TLAAs in 10 CFR 54.21 (c)(1 )(ii), and that

the safety margins established and maintained during the current operating term will be

maintained during the period of'extended operation, as required by 10 CFR 54.21 (c)(1). The

staff also concludes that the FSAR Supplement contains an appropriate summary description of

the TLAA on USE for the period of extended operation, as required by 10 CFR 54.21 (d).

4.2.3 Pressurized Thermal Shock

4.2.3.1 Summary of Technical Information in the Application

In Section 4.2.3 of the LRA, the applicant addressed 10 CFR 50.61 which requires licensees to

protect against PTS transients in PWRs. The applicant stated that the screening criterion in

10 CFR 50.61 is 270 OF for plates, forgings, and axial welds and 300 OF for circumferential

welds. According to this regulation, if the calculated RTpTs for the limiting reactor beltline

materials is less than the specified screening criterion, then the vessel is acceptable with regard

to the risk of vessel failure during postulated PTS transients.

The applicant has updated the RTpTS calculations for Units 1 and 2 to cover the period of

extended operation, in accordance with 10 CFR 54.21 (c)(1 )(ii). The applicant used methods to

calculate the RTPTS which are consistent with RG 1.99, Revision 2. The applicant concluded

that the screening criteria are met for both units. The LRA presents a summary of the results of

these calculations. The applicant stated that the limiting material for Unit 1 is the Lower Shell

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Plate B6919-1,-which has'54 EFPY RTpTs'value-of 191 'F. The applicant stated that the limiting

material for Unit 2 is the Intermediate Shell Plate B7212-1, which has a 54 EFPY:RTps' value of

208 OF. In accordance with the Reactor Vessel Surveillance Program, the applicant may

update the RT 3 calculations to include credibl ~data'from the analysis of future surveillance?'T

capsules. ' -C . , ! '' 

4.2.3.2 Staff Evaluation .

'Title 10, Section 50.61,' of the Code of Federal Regulations provides the Commission's

'requirements f6r demonstrating that RVs in U.S. PWR facilities will have adequate protection'

against the consequences of PTS events throughout their licenised p6riod of operation. The

rule requires licensees to calculate an adjusted ref erence'termperature value for PTS (i.e., the

RTpTs value) for each base metal and weld material located in the beltline region of the plant's

RVs. The rule sets a screening limit of 270 OF for RTpTs values that are calculated for base

metals (i.e., forging and plate materials) and axial weld materials and a screening limit of 300 "F

for RTpTs values that are calculated for circumferential weld materials. The rule also provides

an expanded discussion' regarding how thecalculations of RTp values ~ 'should be performed'.

and describes two methods for determining RTpTs values for RV beltline materials, depending -

on whether or not a given RV beltline material is represented in a plant's Reactor Vessel

Material Surveillance Program. ''

The applicarit provided its RTPTS value assessments for the RV beltline materials of FNP Units 1

and 2 in Tables 4.2.3-1 and 4.2.3-2 of the LRA, respectively. The applicant's RTpTs value

assessments for the FNP units are based on the fluence values listed in LRA Table 4.2.1 for

the clad-to-base metal location of the RVs, as projected to the end of the extended period of

operation (i.e., 54 EFPYs). " - - . -.

The applicant'reported that Lower Shell Plate B6919-1 '(Heat No. C6940-1)'was the limiting

material at FNP, Unit 1, for PTS and calculated an RTpTS value of 191 0F for this material at 54

EFPYs.. To verify the validity of the applicant's limiting 54-EFPY RTPTS value,

the staff performed independent calculations'of the RTpTs values for the FNP, Unit 1 RV thriough

the period of extended operation. The'staff determined that for FNP,'Unit l, Intermediate Shell

Plate B691 9-1 (Heat No.,C6940-1) is the limitirig RV beltline material for PTS. The staff '

calculated an RTpTs value of 184.1 OF for this material at 54 EFPYs using available, credible

surveillance'data for the heat of material at the time of the LRA submission.

The staff noted and confirmed that on Aprii 16, 2004, the applicant submitted WCAP-1 6221 -NP

for FNP, Unit 1. 'The applicant submitted this report to meet the surveillance data reporting

requirements of'10 CFR'Part 50, 'Appendix' H, and to provide the Charpy impact data, neutron

fluence data, tensile test data, and alloyiiib chemisiry data forFNP, Unit 1, Capsule V, which'

was removed from the FNP, Unit 1 RV in the-spring of 2003. This report also updated the'

54-EFPY limiting inside diameter (ID),I/4T, and 3/4T neutron fluence values for the FNP, Unit

1, RV and reassessed all previous surveillance data for'FNP, Unit 1, Capsules Y. ,-and W.

The staff performed an''independent PTS ass-sm` ent, using the revised surveillance capsule

data for the 'unit reported in WCAP-1 6221 -NP, -and determined that the revised surveillan6e -

data 'increases''the limiting' RTp' value for FNP, Unit 1, to 1 95 F, as based on the RTPTs

calculation for Lower Shell Plate B6919-1 (Het No. 06940-i) This demonstrates that FNP,'

Unit 1 ,'RV is a'plate'-limited RV, and the8reisd 54-EFPY RT& valde of 1 95 F coritinues to

meet the PTS screening criteria of 270 OF for'plate-limited Rye. Therefore, the staff concludes

4-9
that the FNP, Unit 1 RV will meet the requirements of 10 CFR 50.61 through the expiration of

the extended period of operation.

The applicant reported that Intermediate Shell Plate B7212-1 (HeatNo. C7466-1) was the

limiting material at FNP, Unit 2, and calculated an RTpTS value of 208 OF for this material at 54

EFPYs. To verify the validity of the applicant's limiting 54-EFPY RTPTs value, the staff

performed independent calculations of the RTPTS values for the FNP, Unit 2 RV through the

period of operation. The staff determined that at FNP, Unit 2, Intermediate Shell Plate B7212-1

(Heat No. C7466-1) is the limiting beltline material for PTS. The staff calculated an RTpTs value

of 208.8 OF for this plate material at 54 EFPYs. This value agrees with the limiting material and

RTpTs value reported by the applicant. Therefore, the staff concludes that the FNP, Unit 2 RV

will meet the requirements of 10 CFR 50.61 through the expiration of the extended period of

operation.

4.2.3.3 FSAR Supplement

Section A.4.1.2 of the LRA includes the following FSAR Supplement summary description for

the TLAA on PTS:

The requirements of 10 CFR 50.61 provide for protection against pressurized thermal shock

events in pressurized water reactors. The screening criterion in § 50.61 is 270 'F for plates. forgings, and axial welds and 300 'F for circumferential welds. According to this regulation, if the

calculated RTpTs for the limiting reactor beltline materials is less than the specified screening criterion, then the vessel Is acceptable with regard to the risk of vessel failure during postulated pressurized thermal shock.

SNC has updated the RTpTs calculations for FNP Units 1 and 2 to include the period of extended

operation, and has determined that the screening criteria are met for both units. The limiting material for FNP Unit 1 has a 54 EFPY RTpTs value of 191 'F. The limiting material for FNP Unit 2

has a 54 EFPY RTpTs value of 193 F. These TLAAs have been shown to be acceptable for the

period of extended operation in accordance with 10 CFR54.21(c)(1)(ii).

The applicant's FSAR Supplement summary description is' consistent with the staff's analysis

for the TLAA on- PTS described in Section 4.2.3.2 of this SER. The FSAR Supplement

summary description idehtifies the applicable'PTS'requirements that the applicant must meet to

ensure continued compliance with 10 CFR 50.61. The FSAR Supplement also discusses why

the RV beltline materials at FNP, Units land 2, will comply with the' applicable requirements'in

10 CFR 50.61, as projected through the expiration of the extended period of operation for the

units. However, the staff determined that the limiting RTpTs value cited by the applicant for

FNP, Unit 2, in the.FSAR Supplement summary description (i.e., 193 OF) was not consistent

with the limiting RTPTs value cited by the applicant' in Table 4.2.3-2 of the' application (i.e., 208

0F, based on Intermediate Sliell Plant B7212-1)' and informed the applicant that this should be

corrected appropriately. The staff identified this request as RAI 4.2.3.3-1.

In its response to RAI 4.2.3.3-1, in SNC Letter No: NL-04-06i 7, dated-April 16, 2004, the

applicant revised the FSAR Supplement'summary description for the PTS assessments to

makw'dthe applicant's 'reported limiting RTpT- value consistent with those values included in

Table 4.2.3 of the LRA and confirmed independently by the 'staff using the Reactor Vessel

Integrity Database (RVID). The revised limiting RTp1. values cited by theapplicant for FNP

Units 1 and 2, in th6. FSAR Suppleiment su'mmary descriptionare 191 Ffor Unit 1 and 239.0F

for. Unit 2. These limiting RTps values conform to or bound the RTpTs values cited by the

4-10
applicant in Table 4.2.3 of the application. Becausethe RT;_8 vfaltfes in the FSAR Supplement

summary description provide conservative values rblative tthd PTS screening criteria, they are

acceptable. On the basis of the applicant's response to RAI 4.2.3.31,'the staff concludes that

the'applicant's FSAR Supplement summrary desiripttfio for the TLAA on PTS is acceptable and

RAI 4.2.3.3-1 is resolved. ' '* ''

As noted previously, the staff performed an independent PTS assessment for FNP, Unit 1,

using the revised surveillance capsule dataif6r the hunit'reported in WCAP-1 6221 -NP,'and

determined that the revised surveillance data resulted in a slight increase to the limiting RTpT';-'

value for FNP Unit 1 (i.e., a revised RTpTs value 6f '195 OF) .-Since this is not a significant-.:

'change in the previous limiting RTp value reported in'the&FSAR'Supplement for the FNP Unit

1 7TS assessment, the staff co cludes that the applicant will not need to update the revised

RTpTS value listed in'the FSAR Suppldm6et'for'Unit'1 'at this time, 'and instead may use the

10 CFR 50.59 process to update the Value bohce'the FSAR'Supplerni6ts are incorporated in'the

FSAR for the units following approval of the renewed license.'

4.2.3.4 Conclusion ; ',: --

The staff has reviewed the applicant's TLAA on PTS, as summarized in Section'4.2.3 of the 4

LRA, and has determined that the RV beltli&nematerials at FNP Units 1 -and 2, will continue to

comply with the requirements foir PTS outlined in -'10 CFR 50.61 throughout the extended period -of operation. The staff therefore concludes that the applicant's TLAA for PTS complies with the

staff's acceptance criterion for TLAAs found in -1 0-CFR 54.21 (c)(1 )(ii), and that the safety ' - margins established and maintained during the cu'rrent operating term will be maintained during

the extended period of operation,'as required by'1 b'CFR 54.21 (c)(1). The staff also concludes

that the FSAR Supplement contains an appropriate summary description of the TLAA on PTS

'for the extended period of operation, as required by IO CFR 54.21(d). :;

4.2.4 Adjusted Reference Temperature ' '

4.2.4.1 Summary of Technical lnformatin iath eApplication"-

In Section 4.2.4 of the LRA, the applicant stated that the calculations it used to determine the''

adjusted reference temperature (ART) for the critical components of the RV meet the definition

of a TLAA pursuant to the criteria of 10 CFR 54.3. 'The applicant updated these calculations for

54 EFPYs in abc6rdanh6e with 10 CFR 54.21 (c)(1 )(ii).-

The 'applicant concluded the mnst limiting tnaierial and location for the' ART for Unit 1 is the

Lower Shell Plate B6919-1, with'an ART at 1/4T-of 182 cF. For Unit 2, the most limiting>-

material is the Intermrediate Shell Plate6B7212-1 with anART at 1/4T of 195 OF. .The applicant

statedthatthe Unpitt2f ART isb 's upon RG 1 99, Revision 2, Position 2.1, using credible

surveillan'ce'6ipsdl6 data.";~ -- :- - - o;.

4.2.4.2 Staff Evaluation - --

1/4T RTNDT values for RV beltline materials are used as part of the inputs to the P-T limit curve

calculations for operating reactors. The ARTs for beltline materials at the 3/4 thickness location

of the RV (i.e., 3/4T RTNDT values) are also used in the calculation of P-T limit curves.

4-11
The staff performed independent calculations of-the-1/4T and 3/4T RTNDT values for the RV

beitline materials at FNP, Units 1 and 2, through 54 EFPYs. The staff based its independent

calculations on the methods described in, RG..1.99, Revision 2. The staff 'also applied the'

neutron fluence values for the 1/4T and 3/4T locations of the FNP RVs, as listed in Table 4.1.2

of the LRA for 54 EFPYs of power operation, for its independent calculations of the 1/4T and

3/4T RTNDT values.

Fof FNP, Unit 1, the staff calculated a limiting 1/4T RTNDT value of 185.1 OF and a limiting 314T

RTNDT value of 161.2 OF for Lower Shell Plate C6919-1 (Heat No C6940-1), using the revised

surveillance data reported inWCAP-16221-NP. The staff determined the revised data that

were not deemed credible, in accordance with the credibility criteria of RG 1.99, Revision 2, and

applied a full margin term to its independent calculations. In contrast to the limiting. 1/4T value'

calculated by the staff, the applicant calculateda limiting 1/4T RTNDT value of 182 OF for FNP,

Unit 1. The limiting 1/4T RTNDT value for FNP, Unit 1, calculated by the applicant is within 3 OF

of the value calculated by the staff using the revised surveillance data. The staff finds this

small difference in the 1/4T RTNDT values to be acceptable, and that it will not significantly

impact the 54-EFPY P-T limits for the FNP, Unit 1, RV.

For FNP, Unit 2, the staff calculated limiting 1/4T and 3/4T RTNDT values of 195.8 0F and

162.9 °F for Intermediate Shell Plate B7212-1 (Heat No. C7466-1), based on credible.

surveillance data and the application of Position 2.1 of RG 1.99, Revision 2.. The applicant also

calculated a limiting 1/4T RTNDT value of 195, F for FNP, Unit 2, using credible surveillance data

for Intermediate Shell Plate.B7212-1 (Heat No. C7466-1). Since the applicant's limiting 54-;

EFPY 1/4T RTNDT value for FNP, Unit 2, is consistent with that calculated by the staff, the staff

finds the limiting 54-EFPY 1/4T RTNDT value for FNP, Unit 2, to be acceptable.

The limiting 1/4T and 3/4T. RTNDT values for RV beltline materials in operating reactors are used

in the calculations of P-T limits that are required to be calculated under the requirements of

Section IV.A.2 to 10 CFR Part 50, Appendix G. The staff determined that the applicant did not

provide the 3/4T RTNDT values for the limiting 3/4T beltline materials in this TLAA. The staff

requested that the applicant provide its calculations of the limiting 3/4T RTNDT values for the RV

beltline materials at FNP, Units 1 and 2, through 54 EFPYs. The staff identified this request as

RAI 4.2.4.2-1.

In its response to RAI 4.2.4.2-1, via letter dated April 16, 2004 (SNC. Letter No. NL-04-061 7),,,

the applicant indicated that the limiting 3/4T RTNDT values for the FNP units are 159 OF for Unit 1

and 163 °F for Unit 2 through 54 EFPYs. In comparison, the staff calculated the limitinig 3/4T

RTNDT values to be 161.2 OF for Unit 1 and 162.9 °F for Unit 2 through 54 EFPYs. The limiting

3/4T RTNDT values calculated by the applicant are within 3 OF of the values calculated by the

staff and are therefore in good agreement. These small differences in the 3/4T RTNDT. values

will not impact the 54-EFPY P-T limits for the RVs. The staff therefor6 concludes that the

limiting 3/4T RTNDT values provided in the applicant's response to RAI 4.2.4.2-1 are acceptable.

Based on this assessment, the staff concludes that the applicant has calculated acceptable

limiting 1/4T and 3/4T RTNDT values for the RV beltline materials at FNP, Units 1 and 2, and

concludes that the applicant's TLAA for the ART calculations is acceptable.

4.2.4.3 FSAR Supplement

The applicant did not include an FSAR Supplement summary description for its TLAA on the

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calculation of the ART values (RTNDT values) for the RV beltline materials at the 1/4T and 3/4T

locations of the FNP RVs. Since the applicant has defined these ART calculations as TLAAs in

Section 4.2.4 of the LRA, the staff informed the'applicant that 10 CFR 54.21 (d) requires the

applicant to include an FSAR Supplement summary description for-the TLAA on the calculation

of th6 limiting 1/4T and 3/4T ART values'(i.e., limiting M14T and 3/4T RTND, values) through 54

EFPYs of operation. The staff identified this as RAI 4.2.4.3-1.

In its response to RAI 4.2.4.3-1, in SNC Letter No. NL-04-0617, dated April 16, 2004, the

applicant indicated that the FSAR Supplement would be amended to include the following

summary description for the TLAA on the 1/4T and 3/4T RTNDT calculations:

SNC updated the calculations to determine the adjusted reference temperature (ART) for critical

.-components of the reactor vessel for 54 EFPY In accordance with 10 CFR 54.21 (c)(1)(ii). The

ART values that apply to the current operating conditions at FNP are Included in the Pressure

Temperature Limits Report (PTLR) for each unit. When the PTLR is updated to Include P-T limit - curves that bound the current level of neutron embrittleiiient for the unit, the updated ART values;

'are included.' '- ; -

The staff approved the FNP PTLR on March 31, 1998. Section 4.2.1.3 of this SER describes

the PTLR process and includes NRC-approved methods for calculating the 1/4T and 3/4T

RTNDT values for FNP, Units 1 and 2. Since the applicant provided acceptable 54 EFPY 3/4T

RTNDT values for the FNP units in response to RAI 4.2.4.2-1 and because the PTLR process

has been approved by the staff, the staff concludes that the proposed summary description

provides an acceptable basis on how the 54-EFPY 1/4T and 3/4T RTNDT values will be applied

to the P-T limit calculations. Based on this assessment, the staff concludes that the FSAR

Supplement summary description for the TLAA on the ART calculations is acceptable. RAI

4.2.4.3-1 is resolved.' - *

4.2.4.4 Conclusion

The staff has reviewed the applicant's TLAA on the calculation of 1/4T and 3/4T ARTs, as

summarized in Section 4.2.4 of the LRA. The staff has also determined that the applicant's

calculation of the 1/4T and 3/4T RTNDT values for the RV beltline materials, as projected through

the period of extended operation for FNP, Units 1 and 2, complies with the recommended,

guidelines of RG 1.99, Revision 2. The staff therefore concludes that the applicant's TLAA for

calculation of the 1/4T and 3/4T ARTs complies with the staff's acceptance criterion for TLAAs

described in 10 CFR 54.21 (c)(1 )(ii), and that the safety margins established and maintained

during the current operating term will be maintained during the period of extended operation, as

required by 10 CFR 54.21(c)(1). The staff also concludes that the FSAR Supplement contains

an appropriate summary description of the TLAA on ART calculations for the period of

operation, as required by 10 CFR 54.21 (d).

4.2.5 Pressure-Temperature (P-T) Limits

4.2.5.1 Summary of Technical Information in the Application

In Section 4.2.5 of the LRA, the applicant addressed Appendix G to 10 CFR Part 50, which

requires that heat up and cool down of the reactor pressure vessel (RPV) be accomplished

within established P-T limits. Plant-specific calculations establish these limits.'The-calculations

utilize materials and fluence data obtained through-plant-specific reactor surveillance capsule

!4-13
programs.

The applicant includes the P-T limit curves for the current operating conditions in the PLTR for

each unit. When the operating conditions of each unit merit the use of a different curve, the

applicant updates the PTLR for that unit to include P-T limit curves that bound the current level

of neutron embrittlement for the unit. The applicant may further update the P-T limit curves

based upon data gained from capsules that the applicant receives in accordance with the

Reactor Vessel Surveillance Program.

4.2.5.2 Staff Evaluation

Paragraph IV.A.2 of 10 CFR Part 50, Appendix G, provides the criteria for generating the P-T

limits that are required for commercial U.S. light-water reactors. As required by 10 CFR 50.36,

licensees owning nuclear power production facilities must include the P-T limits and LTOP

setpoints among the limiting conditions for operation (LCOs) in the plant TS. However, on

August 31, 1996, the staff issued Generic Letter (GL) 96-03, "Relocation of the Pressure

Temperature Limit Curves and Low Temperature Overpressure Protection System Limits," and

provided an acceptable process for revising the LCOs for plant-specific P-T limits and LTOP

setpoints for relocating the actual P-T limit curves and LTOP setpoints out of the LCOs and into

a PTLR. The GL also required that the PTLR be administratively controlled by the

Administrative Controls Section of the TS.

The applicant requested staff approval of a PTLR for FNP, Units 1 and 2, in a license

amendment request dated December 18, 1997. The staff approved the PTLR for FNP,- Units 1

and 2, in its safety evaluation dated March 31, 1998. The FNP PTLR process generates the

FNP P-T limits in accordance with the NRC-approved methodology in WCAP-14040-NP-A,

Revision 2. This approach includes a methodology for calculating the ARTs for the 1/4T and

3/4T locations of the RV, in accordance with the guidelines of RG 1.99, Revision 2, and for

generating the P-T limit curves, in conformance with the requirements of Section IV.A.2 of

10 CFR Part 50, Appendix G, and Appendix G to Section Xl of the ASME Boiler and Pressure

Vessel Code.

The staff's approval of the PTLR in its safety evaluation of March 31, 1998, permits the

applicant to generate the P-T limit curves for the extended -period of operation for FNP, Units 1

and 2, without the need for a license amendment for the curves. FNP TS 5.6.6.c requires the

applicant to submit the PTLR to the staff for "docketing" purposes only when a new fluence

period occurs for the units or when it revises or supplements the PTLR. On the basis of this

review, and the NRC's acceptance that the 54-EFPY P-T limit curves may be processed

through SNC's PTLR process for the FNP RVs, the staff concludes that the applicant's-TLAA

for the FNP P-T limits is acceptable.

4.2.5.3 FSAR Supplement

Section A.4.1.3 of the LRA includes the following FSAR Supplement summary description for

the TLAA on the FNP P-T limits:

Appendix G of 10 CFR Part 50 requires heat-up and cool-down of the reactor pressure be

accomplished within established limits for P-T. Plant specific calculations establish these limits.

The calculations utilize materials and fluence data obtained through plant specific reactor

4-14
surveillance capsule prograrms. '

The PUT limit curves that apply for the current operating conditions at FNP are included in the

Pressure Temperature Limits Report (PTLR) for each unit When the operating conditions of each

unit merit the use of a different curve, the PTLR for that unit is updated to include P-T limit curves

that bound the current level of embrittlement for the unit. SNC has updated the FNP P-T -

calculations, including the adjusted reference temperature (ART) values, to account for 54 EFPY in

accordance with 10 CFR 54.21 (c)(1)(ii). ,-

The applicant's FSAR Supplement summary description for the TLAA'on the P-T limits

appropriately describes the.NRC-approved PTLR process, which was approved in the staff's

safety evaluation of March 31, 1998, as the basis for revising the P-T limits for the extended

period of operation for the FNP units. The staff ;concludes that the'FSAR Supplement summary

description adequately describes the TLAA on the, P-T limits and is therefore acceptabl6.&

4.2.5.4 Conclusion

The staff has reviewed the applicant's TLAA on P-T limits, as summarized in Section 4.2.5 of

the LRA, and has determined that the applicant will generate the P-T limits for the extended.

period of operation for FNP, Units 1 and 2, in accordance with the FNP PTLR. The staff

therefore concludes that the applicant's TLAA for the FNP P-T limits will comply with the

-acceptance criterion for TLAAs described in 10 CFR 54.21 (c)(1)(ii) when the applicant.

generates P-T limits for the period of extended operation and incorporates them into the FNP.

PTLR. Further, the staff concludes that the safety margins established arid maintained during

the current operating term will be maintained during the period of extended operation, as -.

required by 10 CFR 54.21 (c)(1). The staff also concludes that the FSAR Supplement contains

an appropriate summary description of the TLAA on P-T limits for the period of operation, as

required by 10 CFR 54.21 (d). . .

4.3 Metal Fatigue

4.3.1 Fatigue of ASME Class 1 Components:

A metal component subjected to cyclic loading at loads less than the static design load may fail

due to fatigue. :The applicant may have evaluated potential metal fatigue of components on the

basis of an assumed number of transients or cycles for the current operating term. The staff

reviewed the validity of such metal fatigue analysis for the period of extended operation.

4.3.1.1 Summary of Technical Information in the Application

~* i .- ' ." !

The applicant discussed the design of the FNP-reactor coolant pressure boundary (RCPB)-

components in Section 4.3.1 of the LRA.- Components of the RCPB were designed to the

ASME Boiler and Pressure Vessel Code, Section III, requirements for Class 1 components.

Table 4.3.1, "Class 1 'Thermal Fatigue Cycles,", of the LRA lists the FNP FSAR 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 transientcycles for 60 years of plant operation for each unit. The

applicant's estimate indicates that the number of designcycles will remain bounding for the

period of extended operation. In addition to the design of ASME Class 1 -components using the

transient cycles listed in Table 4.3.1 of the LRA, the applicant identified evaluations that it,:

performed to address other specific issues. The applicant performed evaluations for the surge

'4-15
line to address NRC Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification," and the

residual heat removal (RHR) suction lines to address NRC Bulletin 88-08, "Thermal Stresses in

Piping Connected to Reactor C6olant Systems." The applicant indicated that these lines will be

monitored by the FNP Fatigue Monitoring Program (FMP). Section B.5.7 of the LRA describes

the FMP.

The applicant discussed the evaluation of environmentally assisted fatigue of RCPB

components. 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," dated March 1995. The applicant also

used the environmental fatigue correlations in NUREG/CR-6583, "Effects of LWR CoolantEnvironments on Fatigue Design Curves o6fCarbon 'and Low Alloy Steels,"' dated March 1998,

and NUREG/CR-5704, Effects of LWR Coolant Environments on Fatigue Design Curves of

Austenitic Stainless Steels," dated April 1999, in the evaluations.

4.3.1.2 Staff Evaluation

As discussed previously, components of the FNP 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).

The specific design criterion for fatigue analysis of RCPB comp6nents 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 transien t. The

CUF sums the fatigue damage resulting from each transient. The design criterion requires that

the CUF not exceed 1.0. The applicant indicated that the FMP monitors the design transients

at FNP, Units 1 and 2. Table 4.3.1 of the LRA provides the current cycle counts and estimated

cycle counts at 60 years of plant operation for significant transients used in the design of ASME

Class 1 components. Note 5 of Table 4.3.1 indicates that the applicant did not count step-load

change transients before the installation of fatigue monitoring software, and that the number of

these prior transients "would be'estimated using the current fatigue monitoring software. In RAI

4.3.1'-1, the staff req'uested'that the applicantidescribe the method that will be used to estimate

the number of transient cycles that occurred before the installation of the fatigue monitoring

software. The staff also requested that the applicant provide a list of the transients that will be

monitored by the FMP.

In its response to RAI 4.3.1-1, dated February 20, 2004, the applicant described the method

that SNC will use to estimate the'number of step-load change transients that occurred before

the installation of the fatigue monitoring software. The apfplicant indicated that'the estimate of:

step-load transients will be based on the rate determined from five years of fatigue monitoring

data, adjusted by a weighting factor derived from a comparison of the number of previous plant

trips to the number of plant trips during the five year monitoring period.- The'applicant also.

indicated that, beca-use load-follow operation is not used at' FNP, Units 1'and 2, it expects the

number of step-load changes to be a small fraction of the number for design. The staff finds

the applicant's proposed method to estimate previous step transients reasonable and

acceptable.

4-16
The applicant also provided a list-of the transie'nts mnit6r'ed by the'FMP. The staff compared

the list of monitored transients with those listed ihi'FNP FSAR Table 5.2-2. The applicant

monitors all of the normal, upset,'anid test'transiintsiistdd in FSAR Table 5.2-2,' except for unit

loading and 'unloading at 5 percent of full ~p6w-e'r/miniute. The applicant indicated that this

transient was intended to account for plant Ioad'ollwopeation. As discussed above, the

applicant indicated that it does noit use load-f oll'f--&ratidn'at FNP,' Units 1 and 2. The staff:

considers the number of tran sients listed i ithe FNP 'FSAR for these load changes

conservative, based on the information pr6esnted i&nNUREG/CR-6260. Therefore, the staff

agrees with the applicant that it is not ne t6-tr'ack these transients:. On the basis of the

information provided by the applicant, the staff'finds'that the FMP tracks'the'significant 'design

transients listed in Table 5.2-2 of the FNP FSAR.

The Westinghouse Owners Group (WOG) issued WCAP-14577, Revision 1 -A, "Aging

Management for Reactor Internals," in March 2001 to address the aging management of the

'reactor vessel internals (RVI). Section 2.3.1i of the'LRA indicates'that the applicant reviewed

WCAP-14577, Revision 1-A,-as a source of input information for FNP.: The staff's review of

WCAP-1 4577, Revision 1 -A, identified a number of issues' that should be addressed 'on a plantspecific basis. Renewal Applicant Action Item 11 specified in WCAP-1 4577, Revision 1 -A,

indicates that the fatigue TLAA of the RVI 'should be6;ddressed on a plant-specific basis. In

RAI 4.3.1-2, the staff requested that the applicant discuss the design basis f6r the'components

listed in Table 3-3 of WCAP-1 4577, Revision 1 -A, and indicate how fatigue of these

components is managed. _ ' , -' -

In its response to RAI 4.3.1-2, dated February 20;'2004, the 'applicant indicated that it had

evaluated the FNP RVI according to Westinghouse'internal crite'ria which are similar to the

ASME Code criteria. The applicant further indi6ated that the transient cycles used in the I.'

evaluation of the FNP RVI are bourided by those monitored by the FMP. -The applicant

estimated that the number of transient cycles assumed in the design of the FNP RVI 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 A'pplicant Action Item 11 specified in

WCAP-14577,' Revision 1-A, by assuring that the FMP will monitor the design transients that

are significant contributors to design fatit e usage of the RVI components.

The WOG issued WCAP-1i4575-A; uAgini'Management Evaluation for Class 1 Piping and'

Associated Pressure'Boundary Components," in August 1996'to address aging management of

the reactor coolanitfsystem (RCS)pipin Sectioh2.3.1 of the LRA indicates that .

WCAP-14575-A, was reviewed as a source of inpuit information for FNP; Tables 3-2 through:

3-16 of WCAP-14575-A list RCS components for which fatigue is'considered significant. The

staff's review of WCAP-1 4575-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 -RA in'Tables 3-2 through 3-16 of WCAP-14575-A. The

applicant's' FMP monitors the sighificant plant design transients listed in FSAR Table 5.2-2 that

were used in the d6sig 'of the RCPB comporients; Th'e staff finds that the applicant's 'FMP,

which monitors the significant plant de-sign transients, adequately addresses Renewal Applicant

Action Itemr 8. -' -. -,. '

The WOG issued WCAP-1 4574-A, "License Renewal Application: Aging Management

Evaluation for'Pressurizers," in' December 2000 t6'address aging management of pressurizers.

4-417
Section 2.3.1 of the LRA indicates that the applicant reviewed WCAP-14574-A as a source of

input information for FNP. The staff's reviewof, WCAP-1 4574-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 subcomponent CUFs remain below 1.0.for the

period of extended operation. Table 2-10 of WCAP-1 4574-A indicates that the ASME Section

l;l, Class 1 fatigue CUF criterion could be exceeded at several pressurizer subcomponent

locations during the period of extended operation. WCAP-14574-A also identified recent

unanticipated transients that were not considered in the original ASME Section III, Class 1

fatigue analyses, including inflow/oufflow thermal transients., In RAI 4.3.1-3, the staff requested

the applicant to provide the following information:

* confirmation that the additional transients discussed in WCAP-14574-A that were not

considered in the original design have been addressed at FNP

* details on the ASME Section 1II, Class 1 CLB CUFs for the applicable subcomponents of

the FNP pressurizers specified in Table 2-10 of WCAP-.14574-A and the corresponding

CUFs for the extended period of operation

* the impact of the environmental fatigue correlations provided in NUREG/CR- 6583 and

NUREG/CR-5704. on the above results

In its response to RAI 4.3.1-3, dated February 20, 2004, the applicant indicated thaf the FMP

stress-based monitoring of the surge line and pressurizer lower head accounts for the additional

transients discussed in.WCAP-14574-A. The applicant also indicated that all FNP pressurizer

subcomponents have design CUFs equal to or less than those shown in Table 2-10 of

WCAP-14574-A. The applicant indicated that the number of cycles assumed in the design of

these subcomponents exceeds the number expected for 60 years of plant operation, and

therefore, the analyses remain valid for the period of extended operation.

As discussed in Section 4.3.1 of this SER, the applicant performed an additional evaluation of

the pressurizer surge line in response to NRC Bulletin 88-1 1. The applicant's evaluation

indicated that the usage factor, including environmental effects, will remain less than 1.0 for 60

years of plant operation for the surge line and pressurizer lower head. The applicant further

indicated that stress-based fatigue monitoring of the surge line and lower pressurizer will be

used to ensure that the fatigue. usage of these components remains less than 1.0. The staff.

finds that the applicant has adequately addressed Renewal Applicant Action Item 1 of WCAP14574-A by (1) evaluating the fatigue sensitive subcomponents for insurge/outsurge transients,

(2) considering the effects of the reactor water environment, and (3) assuring that the FMP will

monitor the thermal transients that are significant contributors to the design fatigue usage of

RCS components.

The applicant also performed additional evaluation of the FNP RHR suction lines in response to

NRC Bulletin 88-08.:.The applicant committed to use the FMP to monitor the RHR suction line'

transients to ensure that the number of transients used in the evaluation is not exceeded during

the period of extended operation. The staff finds that the applicant's FMP provides an

acceptable program to monitor the RHR suction line fatigue usage during the period of

extended operation, in accordance with the requirements of 10 CFR 54.21 (c)(1)(iii).

The applicant indicated that the FMP will continue during the period of extended operation and

4-18
will assure that design cycle limits are not exceeded. The applicant's FMP tracks transients and

cycles of RCS components that have explicit designr 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," raisedbconcerns regarding the conservatism of the

fatigue curves used in the'design of the 'RCS components.' Although GSI-1 66 was resolved for

the current 40 year design life'of operating components,7the 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, 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-190 is closed. -This conclusion is based

primarily on the negligible calculated increases in core damage frequency in going from

40 to 60 year lives. However, the calculations supporting resolution of this issue, which

included consideration of environmental effects, and the nature of age-related

degradation indicate the potential for an increase in the frequency of pipe 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. -

The applicant indicated that it evaluated six component locations equivalent to those identified

in NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected

Nuclear Power Plant Components," dated February 1995, for a newer vintage'Westinghouse

plant. The staff notes that FNP consists of three-loop Westinghouse plants, whereas the newer

vintage plant in NUREG/CR-6260 is a four-loop Westinghouse plant. Consequently, some of

the component locations were not directly comparable. The applicant selected an alternative

location for the safety injection nozzle. NUREG/CR-6260 evaluated the boron injection line

cold-leg nozzle. At FNP, Units 1 and 2, the boron injection line connects to the residual heat

removalsafety injection (RHR/Sl) line. Therefore, the applicant selected the boron injection line

tee connection to the RHR/SI line. The applicant also evaluated the RHR/SI RCS cold-leg

nozzle. The staff finds these locations to be acceptable for evaluating environmental fatigue.

The staff compared the applicant's calculated fatigue usage factors with those listed in -,

NUREG/CR-6260.' The applicant's calculated fatigue usage factors were comparable to those

in NUREG/CR-6260'for the RV shell, inlet/outl6t nozzles, and charging nozzle. Since the,

applicant used the' boron injection tee connection' to th61RHRISI line, a comparable;,

NUREG/CR-6260locatiorn does-not exist. 'However,the applicant's calculated usage factor for

the RHR/Si RCS cold-leg'nozzle is comparable to the SI nozzle usage factor listed in . NUREG/CR-6260. The applicant's calculated usage factor for the surge line hot-leg nozzle is

much lower than the value listed in NUREG/CR-6260 because the applicant uses stress-based

fatigue monitoring at that location.

The calculated fatigu6 usage factors for the vessel and inletloutlet nozzles were below 1.0 for

both units. The staff finds these resu6lts acceptable, on the basis of their comparison to the

results presehted in'NUREG/CR-6260 for a-newer'vintage Westinghouse plant. The applicant's

evaluation of the boron injection tee connection to the RHR/SI line indicated that the usage

factor for both units was well below the allowable limit of .1.0. The staff finds this result

k4-19
acceptable, on the basis of the low design fatigue usage factors reported by the applicant at

these locations. The applicant indicated that the fatigue usage for the FNP surge line hot-leg

nozzles is not expected to exceed 1.0 during the period of extended operation. The applicant's

assessment was based on a projection of the average fatigue usage obtained for six Unit 1

cooldown/heatup cycles and four Unit 2 cooldown/heatup cycles obtained from the stress-based

fatigue monitoring software. In RAI 4.3.1-4, the staff requested the applicant to describe the

stress-based fatigue monitoring of the surge line hot-leg nozzle. The staff also requested that

the applicant indicate whether there were any changes in the plant operations since the startup

of Units 1 and 2 that could affect the fatigue usage of the surge line hot-leg nozzle.

In its response to RAI 4.3.1-4, dated February 20, 2004, the applicant discussed the FNP

stress-based monitoring of the surge line and pressurizer lower head. The applicant indicated

that FNP uses the modified steam bubble method during heat up to mitigate the effects of

insurge/outsurge transients.: The applicant indicated that the current method of operation was

established early in the plant life. In order to account for operation prior to the establishment of

the current procedure, the applicant applied a factor of 1.5 to the measured stress-based CUF.

The staff finds the applicant's procedure to be a reasonable method of estimating the fatigue

usage prior to the establishment of the current method of operation.

The applicant's evaluation indicated that the calculated usage factors may exceed 1.0 for two

components, the charging nozzle and the RHR/SI nozzle to the RCS cold leg. The applicant

committed to take corrective actions before the period of extended operation to address these

components. The corrective actions would include one or more of the following four options:

* further refinement of the fatigue analyses

* repair of the affected locations

* replacement of the affected locations

* management of the effects of fatigue through the use of an augmented, NRC-approved

inservice inspection program

In order to pursue the fourth option, the applicant must use an NRC-approved inspection plan to

obtain NRC approval of its proposed inservice inspection program to manage fatigue prior to

the period of extended operation by submitting a license amendment request. After the NRC

approval of the inspection program, any future changes to the inspection program will be

evaluated in accordance with the 10 CFR 50.59 process. The staff finds the applicant's

proposed options provide acceptable plant-specific approaches to address the charging nozzle

and the RHR/SI nozzle for the period of extended operation, in accordance with 10 CFR

54.21 (c)(1).

4.3.1.3 FSAR Supplement

The applicant provided an FSAR Supplement summary description of the FMP in Section A.3.2

of the LRA, and a description of its TLAA evaluation for ASME Section 111, Class 1 component

fatigue analysis in Section A.4.2.1 of the LRA. On the basis of its review of the FSAR

Supplement, the staff concludes that the summary description of the applicant's actions to

address fatigue of ASME Section 11I, Class 1 components is adequate.

4-20
4.3.1.4 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 FSAR Supplement for the TLAA and finds its description of the 'metal fatigue -

TLAA for ASME Section 111, Class 1 componentis sufficient to satisfy 10 CFR 54.21(d).-

4.3.2 Fatigue of the Reactor Coolant Pumfp Flywheel

As required by 10 CFR 54.21,' applicants for license renewal must manage timre-dependent

aging effects by one of three acceptable methods:

(1) demonstration that the time-limited aging analysis on the aging effect for the current

operation term remains valid for th'pe'riod of extended operation

(2) demonstration that the time-limited aging analysis on the aging effect for the current

operation term has been projected to the end of the period of extended operation

(3). demonstration that the effect of aging on'the intended functions will be adequately V

managed for the period of extended operation ' - '

The reactor coolant pump (RCP) flywheels ini PWR-type light-water reactors are designed with - rotors and discs that revolve at highlspeeds. The high-speed cycling of the rotors and'discs

can make the components susceptible to'crack initiation and growth byfatigue, which is a timedependent aging mechanism. The regions of the flywheels that are most susceptible to low--

cycle fatigue are located at the corners of the locking mechanisms in the flywheel rotors and

discs. These corners act as stress risers which Imake the corners more highly susceptible to ' the initiation arid growth of fatigue-indued crabking. 'Applicants owning plants that include RCP

flywheels in the plant designs must therefore demonstrate that initiation and growth 6f a crack

in the RCP flywheel rotors anid discs will be adequately managed in accordance with one of the

three acceptable nethods designated by the staff in 10 CFR 54.21 (c)(1).'

4.3.2.1 Summary of Technical Information in the Application

The applicant stated that the'design of the flywheels for the RCPs at FNP assumes that the

pump will be subjected to 4000 start/stopIcyces, and that the calculations that prove the design

envelop the life of the component. The applicant stated that SNC cbnservatively'elects to treat

these calculations as TLAAs, and that the assumption of 4000 start/stop cycles is conservative

for 60 years 6f operation. The applicant stated that the existing calculations are therefore

adequate and do not' require updating for icense renewal.(i.e. they do no require- ' demonstration,- in accordance with 10 CFR 54.41 (c)(1 )(i)).

Section 5.2.6 ofthe FNP FSAR provides'a discussion'of the design basis for the RCP

flywheels, and Figure 5.2- 1 of the FNP FSAR illustrates the design basis for their material

properties and minimum fracture toughness properties. " ' ' -

4-21
4.3.2.2 Staff Evaluation

RG 1.14, Revision 1, "Reactor Coolant Pump.Flywheel Integrity," issued August 1975, provides

the staff's recommended acceptance criteria for material and minimum fracture toughness

properties of SA 508, Class 2 and 3 materials, and SA 533 Grade B, Class 2 materials used in -

the fabrication of U.S. RCP flywheels. RG 1.14, Revision 1, also provides acceptable'

guidelines for performing the structural integrity assessments for the RCP flywheels in U.S.

light-water reactors, including the assessments for ensuring the integrity of the flywheels

against unacceptable fatigue-induced crack growth failures. These fatigue assessments are

based on fatigue-induced crack growth associated with the number of start/stop cycles

assumed in the design' basis for the pumps. Therefore, to meet the acceptance criterion of 10

CFR 54.21 (c)(1)(i), the applicant must demonstrate that the total number of RCP start/stop

cycles projected through the end of the extended period of operation for each of the FNP units

will be bounded by the number of RCP start/stop cycles assumed in the 60-year, fatigueinduced crack growth analysis for the FNP RCP flywheels (i.e., based on a bounding analysis of

6000 RCP start/stop cycles).

In RAI 4.0-1, the staff requested the applicant to clarify whether the number of RCP start/stop

cycles assumed in the 60-year RCP flywheel crack growth analysis was based on 4000

start/stop cycles or 6000 start/stop cycles. The hpplicant responded to RAI 4.0-1 in SNC Letter

No. NL-04-0617, dated April 16, 2004. The applicant clarified that it'assumed 6000 RCP

start/stop cycles in its 60-year analysis. The staff concludes that the applicant's response to

RAI 4.0-1 is acceptable because it clarifies the number of ROP start/stop cycles the applicant

assumed in its 60-year RCP flywheel crack growth analysis. On the basis of the applicant's'

response to RAI 4.0-1, the staff concludes that RAI 4.0-1 is resolved.

In its application, the applicant concluded that the results of' the TLAA' for the RCP flywheels at

FNP, Units 1 and 2 (i.e., the TLAA assessment in the CLB), remain valid for the extended

period of operation for the'units and therefore meets the accel tance criterion in

10 CFR 54.21 (c)(1)(i). By letter dated December 5, 2003, SNC provided the following

supplement to the TLAA description for the RCP flywheels (LRA Section 4.3.2):

For FNP, WCAP-15666 and WCAP-14535A bound the issue of cracking of the reactor coolant

pump flywheel. For both analyses, the fatigue crack growth evaluation Is performed in accordance

with the ASME Code, Section Xl requirements. These analyses show that, for a bounding set of

flywheels, the fatigue crack growth is negligible. In the WCAPs, the FNP flywheels were included,

in Group 5. Group 5 is bounded by Groups 1 and 2 for the purposes of the evaluation. The results

of the evaluation area crack growth of approximately 0.08 inches in the bounding Groups,

assuming 6000 start and stop cycles in a 60 year operating life.

For FNP, the number of reactor coolant pump start and stop cycles is anticipated to be significantly

less than 6000, even considering the extended license term. The number of reactor shutdowns is

anticipated to be less than 200 (reference LRA, Section 4.3.1) and that would mean exceeding 30

start/stop cycles of the reactor coolant pumps per shutdown. FNP uses vacuum refill from a

shutdown condition, which means that the RCPs are stopped and re-started once per shutdown

under normal conditions. Given that the fatigue crack growth is not significant, and the number of

start/stop cycles anticipated is so much less than assumed in the evaluation, SNC has concluded

that the fatigue growth analysis is not significant to the aging of the reactor coolant pump flywheel.

However, SNC conservatively elects to call this issue a TLAA. It is further significant to note that

FNP has Technical Specification requirements to inspect the flywheels in accordance with the ISI

Plan (TS 5.5.7).

4-22
The applicant's supplemental inform tio es that the applicani's fatigue'crack growth

analyses assumed the occurrence of 6000'RCP sta&stop cycles through the'expiration'of the

extended period of operation for the FNP units and a'crack growth of 0.08 inches. The fatigue

analyses in LRA Section'4.3 for ASME Code Cdiss' 1 'crmponents coniservativeljassume the'

occurrence of 200 plant startup and trip cycles thro~ugh 60 years'of licensed operations Based

on these assun'ptions, the supplemental'information indicates that'it would take ove'V30 RCP

start/stop cycles per plant shutdown to exceed the allowable crack gronthof 0.08 irichs'. The

staff concludes that this number of start/stop cycles is beyond the normal number of RCP

start/stop cycles that would be expected to occur during any plant shutdown. Based on this,

assessment, the staff concludes that the RCP flywheels have a sufficient margin against

fracture for the period of extended operation for the FNP units, and that the fatigue crack - -

analysis for the RCP flywheels remains valid for the extended period of operation for the FNP

units.. Based on this'assss~ment, the staff concludes that the TLAA for the RCP flywheels, as

described in' LRA Sectior'4.3.2 anid sUpplem6ntid by the informatioi 'provided in the applicant's

letter of April 16,2004, cdmplies with 10 CFR 54.21 (c)(1 )(i) and is therefore acceptable.

4.3.2.3 FSAR Supplement . - :

As required by 10 CFR 54.21 (d), applicants for license renewal must include 'an FSAR

Supplement summary description of the "programs and activities for managing the effects of

aging and the evaluation of time-limited aging 'analyses for the period of extended operation."

On December 5,2003, the applicant provided the following'FSAR Supplement summary -

description for'the TLAAon fatigue-induced crack growth of the FNP RCP flywheels:

A.4.2.3 Reactor Coolant Pump Flywheel Fatigue

In WCAP-14535A and WCAP-1 5666, Westinghouse has generically analyzed the potential for,

cracking due to fatigue in Reactor Coolant Pump (RCP) flywheels. These two Westinghouse ' , analyses are applicable to FNP. The evaluations of the growth of an assumed crackin the

flywheel uses the assumption that the RCPs will experience 6000 start/stop cycles over 60 years

of operation. The evaluations show that the crack growth is negligible for the flywheel model that

bounds those in the RCP at FNP. The number of start/stop cycles for the FNP RCPs is estimated

to be significantly less than 6000 through the period of extended operation. Therefore, these

-analyses are valid for FNP through the period of extended operation (demonstration In accordance

with 10 CFR 5421(c)(1)(i)). - - ' -

The applicant's FSAR Su'pplement'summarm description for the TLAA on the RCP flywheels, as

discussed in SectionA4.2.3of the LRA, ovides a reference to"WCAP'1 4535A and

WCAP-15666: These'documents a'Ye applicable' to FNP and reflect the information given in

Section 4.3.2 of the LRA,'as supplemented by'the additional information on the flywheel:

analyses that the applicant provided in its letter of December mSAR5, 2003: Because the 

Supplement summary description for the TLAA reflects the applicant's compliance with

10 CFR 54.21 (c)(1)(i), the staff c6ncludes 'that the FSAR Supplement summary description for

the RCP flywheels is accepmableand'meets the'requirements of 10 CFR 54.21 (d).

4.3.2.4 Conclusion

The staff has reviewed the applicant's TLAA for fatigue-induced crack growth of the FNP RCP

flywheels, as 'described in Section 4.3.2 'of the 'FNP LRA: The staff has also determined that

the current fatigue-indu ed crack growth a sessmentfor the FNP RCP flywheels remains

bounding for the periods of extended operation for FNP Units 1 and 2. The staff therefore

4-23
concludes that the applicant's TLAA for fatigue-induced crack growth of the RCP flywheels

complies with the acceptance criterion for TLAAs found in 10 CFR 54.21 (c)(1)(i), and that the

safety margins established and maintained during the current operating term will be' maintained

during the period of extended operation,' as required by 10, CFR 54.21 (c)(1).' The staff 'also

concludes that the FSAR Supplement contain's an appropriate summary description of the

TLAA on fatigue-induced crack growth of the RCP flywheels for the' period of extended

operation, as required by 10 'CFR 54.21(d).

4.3.3 Fatigue of ASME Non-Class 1 Components

4.3.3.1 Summary of Technical Information in the Application

The applicant discussed the evaluation of ASME Class 2 and 3 and American National

Standards Institute (ANSI) B31.1.componehns in Section 4.3.3 of the LRA. ASME Class 2 and

3 and ANSI B31.1 require that a stress reduction factor be applied to the allowable thermalbending stress range, if the number of full-range cycles exceeds 7000. The applicant indicated

that most piping systems within the scope of license renewal are bounded by 7000 thermal

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 identified two systems, the sampling system tubing and the air start system for

the emergency diesel generators (EDGs), that may experience greaterjthan 7000 cycles. The

applicant indicated that the sampling system was designed for 22,000'cycles and that this

number of cycles would not be exceeded during the period of extended operation. The

applicant also stated that an evaluation of the air start system indicated that the equivalent

number of full-temperature cycles is less than 7000. Therefore, the applicant concluded that

the piping analyses for these systems will remain valid for the period of extended operation, in

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

4.3.3.2 Staff Evaluation

As discussed above, ASME Class 2 and 3 and ANSI B31.1 require that a stress reduction

factor be applied to the allowable thermal bending stress range, if the number of full-rarige

cycles exceeds 7000. The applicant indicated that most piping systems within the scope of

license renewal are bounded by the 7000 cycles. The applicant also indicated that the.

sampling system was designed for 22,000 cycles and that this number of cycles would not be

exceeded during the period of extended operation. The staff agrees with the applicant's

conclusion that the analyses of these systems remain valid for the period of extended

operation, in accordance with 10 CFR 54.21 (c)(1)(i).

The applicant indicated that the number of thermal cycles for the EDG air start system may.

exceed 7000 during the period of extended operation. The applicant also indicated thatfthe

equivalent number of full-temperature cycles will be less than 7000 cycles. In RAI 4.3.3-1, the

staff requested the applicant to describe the method used to calculate the equivalent number of

full-temperature cycles.

s. I - ! . t_.v '

In its response to RAI 4.3.3-1, dated February 20, 2004, the applicant described the evaluation.

of the EDG air start-system. The applicant indicated that the FNP air start system actuates'

4-24
several times a day to recharge the air pressure in the receivers which is lost due to normal

leakage. The applicant installed temperature-monitoring equipmrtent to measure the

temperature downsteam of the compressors over several days of normal operation. The

applicant used these data to determine the number and magnitude of the temperature cycles.

The measured temperature during each cycle was significantly less than the maximum;

temperature reached when the air receivers are fully recharged following major EDG

maintenance. The applicant used the provisions of the ASME Code, Section 1I1, 1971 Edition,

NC-361 1.1 to calculate the number of equivalent full-temperature cycles based on theI

measured temperatures during daily cycling of the compressors. The calculated number of

equivalent full-temperature cycles was significantly less than the 7000-cycle limit. The staff

finds that the applicant's evaluation satisfies the ASME Code requirement and is therefore

acceptable. The staff also finds that the applicant projected the piping analysis of the EDG air

start system to the end of the period of extended operation, in accordance with

10 CFR 54.21 (c)(1 )(ii).

4.3.3.3 FSAR Supplement

The applicant provided an FSAR Supplement summary description of its TLAA evaluation for

ASME non-Classl components in Section A.4.2.2 of the LRA. On the basis of its review of the

FSAR Supplement, the staff concludes that the summary description of the applicant's actions

to address fatigue of ASME non-Class 1 components is adequate.

4.3.3.4 Conclusion

The staff has reviewed the applicant's metal fatigue TLAA and concludes the applicant's actions

and commitments satisfy the requirements of 10 CFR 54.21 (c)(1). The staff has also reviewed

the FSAR Supplement for the TLAA and finds that the FSAR Supplement contains a description

of the metal fatigue TLAA for ASME Code, Section 11I, Class 2 and 3 and ANSI B31.1

components sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.3.4 Containment Tendon Prestress

4.3.4.1 Summary of Technical Information in the Application

The applicant stated that to meet the requirements of 10 CFR 50.55a(b)(2)(ix)(B), it uses an

analysis to predict the amount of residual prestress in the containment tendons for FNP, Units 1

and 2. The applicant further asserted that the analysis meets the definition of a TLAA, and that

it performed a new analysis to estimate the amount of residual prestress in the tendons after 60

years of operation to demonstrate compliance with 10 CFR 54.21 (c)(1 )(ii). The new calculation

includes the latest measurements of containment tendon prestress taken since the plant began

commercial operation. The calculation indicates that acceptable containment tendon prestress

will continue to exist throughout the period of extended operation. The applicant further stated

that it may update this analysis with future results of the anchor pull testing performed in

accordance with the IWL Inservice Inspection Program (Appendix B.3.1).

4.3.4.2 Staff Evaluation

The applicant provided a description of the TLAA without providing any quantitative comparison

-4-25
of the present level of the prestressing forces based on the measurements, trend lines, and

projected forces during the extended period of operation. In order to understand the basis for

its assertion, the staff requested the following in RAI 4.3.4-1:

10 CFR 54.21 (c)(1 )(ii) requires that the applicant demonstrate the adequacy of the

analysis projected for the extended period of operation. In order for the staff to make a

reasonable assurance conclusion, the applicant is requested to provide the following

information:

* Minimum required prestressing forces for each group of tendons,

* Trend lines of the projected prestressing forces for, each group of

tendons based on the regression analysis of the measured prestressing

forces (see NRC Information Notice 99-10 for more information).

* Plots showing comparisons of prestressing forces projected to the end of

the extended period of operation with the minimum required prestress for

each group of tendons.

In its response to RAI 4.3.4-1 (a), dated April 16, 2004, the applicant provided the following

information:

(a) The following are the minimum required prestressing forces per tendon (170 wires/tendon):

Hoop Tendon = 1021.7 kips/Tendon

Dome Tendon = 1079.5 kips/Tendon

Vertical Tendon = 1157.7 kips/Tendon

In response to (b) and (c), the applicant provided the trend lines for the hoop, vertical, and

dome tendons in graphical and tabular form. This information is as follows for the hoop

tendons:

4-26
Trend lines for the .hoop tendons ,. . . .. .. .I

Year Tendon No of Wires Actual Force Year Tendon No of Wires Actual Force

(kips) (kips)

0.1 All Avg. 169.14 1440.1 5.5 H398C 170 1249.5

3.5 HiBA 170 - 1322.6 7.5 H8AB 166 1- 208.5

3.5 H6BA 166 1306.4 7.5 H14AB 170 1190.0

3.5 H12BA 163 1279.5 7.5 H18CA 170 1183.2

3.5 H17BA 170 1278.4 7.5 H20CA 170 -- 1162.8

3.5 H24BA 170 1339.6 7.5 H25BC 170 1218.9

3.5 H25CA A168 1307.0 7.5 H33BC 170 1212.1

3.5 H29BC 170 1312.4 - 7.5 H36AB -170 1210.4;

3.5 H32BA 170 1307.3- -7.5 H38CA 170- 1200.2

3.5 H36CA 170 1312.4 7.5 HH40BC 170 1198.5

3.5 H39BC 170 1300.5 7.5 H44CA 170 1235.9

5.5 H6AB 166 1248.3- 12.5 -H2AB - 166- - 1231.7

5.5 H12AB 162 1195.6 12.5 H26AC 170 - 1217.2

5.5 H25CA 167 1190.7 I12.5 H44BC 169 1269.2

5.5 H26AB 166 1165.3 17.5 H18CB 170 1147.5

5.5 H29AB 170 1190.0 17.5 H27CA 169 1177.9

5.5 H30CA 169 1240.5 17.5 H42BA -169 1225.2

5.5 H36CA '170 1256.3 - 22.5 H3BA 168 - - 1228.1

5.5 H36BC 170 1232.5 22.5 H26CB -'170 1144.1

5.5 H39AB 164 1130.0 22.5 H42CA 170 1242.7

4-

_ . !. '

I -

-4-27
UNIT I HOOP TENDONS

ACTUAL FORCE TREND PER TENDON BASIS

(from past 6 surv.illanc-s)

I'A.

.1

500

1450

1400 .... JL. ..

1350 .

1100

1250

2 2 0 0i . e & O 2 K p

1000

,LActuoL rorc / Tenon

- Trend Z

0.1 1 10 100

TrARS

The staff recognizes that subsequent inspections could result in a change in the trend line

slopes. However, the applicant will ranage this attribbte by its Containment Inservice

Inspection Program. On the basis of the additional information provided by the applicant, as

well as the staff's evaluation, the staff considers the applicant's TLAA related to prestressing

forces in the prestressing tendons of the FNP containment to be acceptable.

4.3.4.3 FSAR Supplement

Section A.4.3 of the LRA summarizes the applicant's analysis, without providing any

quantitative existing and target values of prestressing forces. By RAI 4.3.4-2, the staff

requested that the applicant provide the following information:

Section A.4.3 in the UFSAR Supplement of the LRA, the applicant states, "The

calculation indicates that acceptable containment prestress will continue to exist

throughout the extended period of operation." In order for the summary to be

meaningful, as a minimum, the applicant should provide a Table showing the minimum

required prestressing forces and the projected (to 60 years) prestressing forces for each

group of tendons which would demonstrate the validity of the analysis results. The

applicant is requested to supplement this information in Section A.4.3 of the UFSAR

Supplement.

In its response to RAI 4.3.4-2, dated March 5, 2004, the applicant committed to supplement

Section A.4.3 of the LRA. The minimum required prestressing forces for the vertical, hoop, and

dome tendons are 1157.7 kips/tendon, 1021.7 kips/tendon, and 1079.5 kips/tendon,

respectively.

4-28
With this addition to the FSAR Supplement, the staff considers the information provided in

Section A.4.3 to be acceptable..' '2- -

4.3.4.4 Conclusion

On the basis of its review of the TLAA, the staff concludes that barring significant deviation in

prestressinig forces caused by time-dependent eff ets (creep and shrinkage of concrete and

relaxation of 'prestressing forcesj), there is a reasonable assuran'e that the containment

prestre'ssing' tendons will pei16m thmirinteded function durig the period of extended - -

operation, as required by 10 CFR 54.21 (c)(1)(ii).-

4.3.5 Fatigue of Reactor Vessel Supports ' -

4.3.5.1 Summary of Technical Information in the Application

The applicant discussed the fatigue analysis of the RV supports in Section 4.3.5 of the LRA.

The applicant indicated that WCAP-14422, Revisi6n 2-A, identifies fatigue of the RV supports

as a potential TLAA, if the supports were constructed in accordance with the 1963 version of

the American Institute of Steel Constru6tior (AISC) manual. The applicant indicated that FNP

used the 1969 version of the AISC manual and, therefore, the existing analyses remain valid for

the period of extended operation, in accordance with 10 CFR 54.21 (c)(1)(i).

4.3.5.2 Staff Evaluation

WCAP-1 4422, Revision 2-A, contains a generic fatigue assessment for Reactor Coolant'

System (RCS) supports, including the RV suppo~fs_.- The WOG' assessment concluded that

fatigue is'not a-n' aging effect that is a concern for.the RCS support structures. The staff's

safety evaluation agreed with the WOG concusion for the materials represented in Table 2-4 of

WCAP-14422, Revision 2-A. Renewal Appli6ant Action Item- 6 indicated that a license renewal

applicant should Justify any.difference between the naterials used for the RCS supports and

those listed in the WOG report. Section 3.3.1.7 of thestaff's safet evaluation'indicates that --

supports designed and constructed using the 1963 AISC manual may have been fabricated -

from materials that are not bounded by the WOG evaluation. The applicant indicated that FNP

usedthe 1969 version of the'AISC manual and, th6ref ore, the concern identified in Renewal

Applicant Action Item 6 is not applicable to FNP. 1Tabl6 2-7 of WCAP-1 4422, Revision 2-A

indicates that the 1969 AISC manual was~"e'd for the FNP supports. As a-consequence, the.

staff concludes no FNP evaluation 'was required to address Renewal Applicant Action Item 6.

4.3.5.3 FSAR Supplemlent - - ; . - . -

In Section4.3.5 of the' LRA, the applicant stated tlhit it used alater edition of the AISC for RCS

support design. It-did not provide any'FSAR supplemnent in Appendix-A' of the LRA-. By letter

dated July 27, 2004,' the applicant stated that becauste"no fatigue-calculationi exist for RCS

supports, and that there is no applicable aging mechanism to address, it determined that a

TLAA does not exist for this issue. Therefore, it did not include a corresponding section in the

FSAR Supplement for fatigue of reactor vessel supports. The staff agrees with the applicant's

statement and conclusion.

4-29
4.3.5.4 Conclusion

The staff has reviewed the applicant's evaluation of fatigue of the RV supports and concludes

that the applicant's actions satisfy the requirements of 10 CFR 54.21 (c)(1)(i).

4.4 Environmental Qualification of Electrical Equipment

The 10 CFR 50.49 environmental qualification (EQ) program has been identified as a TLAA for

the purposes of license renewal. The TLAA of EQ electrical components includes all long-lived,

passive and active electrical and instrumentation and controls (I&C) components that are'

important to safety and located in a harsh environrrent. The harsh environments of the plant

are those areas that are subjected to environmental effects by a loss-of-coolant accident

(LOCA) or a high-energy line break (HELB). The EQ equipment comprises safety-related and

Q-list equipment; nonsafety-related equipment, the failure of which could prevent satisfactory

accomplishment of any safety-related function; and the necessary post accident monitoring

equipment.

As required by 10 CFR 54.21 (c)(1), the applicant must provide a list of EQ TLAAs in the LRA.

The applicant shall demonstrate that one of the following is true for each type of EQ

equipment-(i) the analyses remain valid for the period of extended operation, (ii) the analyses

have been projected to the end of the'period of extended operation, or (iii) the effect of aging on

the intended function(s) will be adequately managed for the period of extended operation.

4.4.1 Summary of Technical Information in the Application

The applicant stated in LRA Section 4.4, "Equipment Qualification," that its Environmental

Qualification Program was established to demonstrate that certain electrical components are

qualified to perform safety functions in the harsh environment following a design-basis accident

(DBA). Elements of the proof of qualification involve the original 40-year license period.

Hence, the qualification reports and calculations that comprise the EQ program meet the

definition of a TLAA. In general, the applicant did not establish qualified lives for the

components within the Environmental Qualification Program longer than the original 40-year

license period.

As a result of its application, the applicant has stated that no additional components will be

added to the Environmental Qualification Program. The applicant has already determined the

qualified service lives for the EQ components and tracks them to determine when a component

is nearing the end of its service life. For those components that are nearing the end of their

qualified service life, the Environmental Qualification Program has provisions for the

components to be reevaluated for longer service, refurbished, requalified, or replaced. The

Environmental Qualification Program complies with the requirements of Appendix B to

10 CFR Part 50 and receives routine quality assurance audits., The applicant will continue this

program through the extended period of operation (Appendix B.3.7), hence the TLAAs will be

managed by an AMP, in accordance with 10 CFR 54.21(c)(1)(iii). The applicant also included a

list of EQ packages in Table 4.4 of the LRA.

4-30
4.4.2 Staff Evaluation

The staff reviewed Section 4.4 of the LRA to determine whether the applicant submitted

sufficient information to meet the requirements of 10 CFR 54.21 (c)(1). For the electrical

equipment identified in LRA Table 4.4, the applicant relies on 10 CFR 54.21 (c)(1 )(iii) in its TLAA

evaluation to demonstrate that the aging effects of EQ equipment will be adequately managed

during the period of extended operation. The staff reviewed the EQ program to determine

whether it will assure that the electrical and l&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'. qualifications focused on how the

Environmental Qualification Program manages the aging effects in order to meet therequirements delineated in 10 CFR 50.49.-:

The staff conducted an audit of the information provided in the LRA and the program bases - documents, which are available at the applicant's engineering office. The audit findings and -

conclusions are documented in Audit and Review Report for Plant Aging Management Reviews

and Programs, Farley Nuclear Plant, Units 1 and 2. On the basis of its audit, the staff finds that

the applicant's Environmental Qualification Program, which the applicant claimed to be

consistent with GALL AMP X.E1, Environment Qualification of Electrical Components," is..

consistent with the EQ program in the GALL Report. Therefore, the staff finds that the'

applicant's Environmental Qualification Program is capable of programmatically managing the

qualified life of components within the scope of the program for license renewal. The

applicant's continued implementation of its Environmental Qualification Program provides

reasonable assurance that the aging effects will be managed, and that components within the

scope of the Environmental Qualification Program will continue to perform their intended

functions for the period of extended operation. -

4.4.3 FSAR Supplement

The applicant provided FSAR Supplement summary descriptions of its Environmental

Qualification Program in Section A.3.1 of the LRA, and EQ calculations in Section A.4.4 of the

LRA. On the basis of its review of the FSAR Supplement, the staff concludes the summary

descriptions of the applicant's actions to address EQ of electrical components are adequate.;

4.4.4 Conclusion . -

On the basis of this review, the staff concluded that the applicant has demonstrated that the

effects of aging on the intended functions of electrical components will be adequately managed

for the period of extended operation by the existing!Environmental Qualification Program, as

required by 10 CFR 54.21 (c)(1 )(iii):. The staff also concluded that the FSAR Supplement,

contains a summary description of the programs and activities for-the evaluation of EQ of

electrical components, as required by 10 CFR 54.21 (d).

4.5 Other Plant Specific Analyses

In Section 4.5 of the LRA, the applicant provided its evaluation of plant-specific TLAAs. The

TLAAs evaluated include the following: : -

4-31
* ultimate heat sink silting

* leak-before-break analysis

* RHR relief valve capacity verification calculations

4.5.1 Ultimate Heat Sink Silting

4.5.1.1 Summary of Technical Information in the Application

In accordance with 10 CFR 54.17, the applicant submitted an evaluation of the TLAA of the

ultimate heat sink (UHS) at FNP, Units 1 and 2. In its letter dated October 9, 2003, the

applicant provided supplemental information to Section 4.5 of the LRA. Section 4.5.1 of the

LRA discusses the UHS, which is a pond where silt deposition' (silting) may occur. Excessive

silting could adversely impact the capability of the service water system to perform its safety

function to achieve a safe shutdown and maintain long-term cooling of the plant following a

DBA.

The applicant stated that it conducts routine soundings of the UHS once every five years to

confirm the water volume in the pond. The applicant evaluates the acceptability of these

soundings to confirm the basis for TS 3.7.9, which requires the pond elevation to be checked,

every 24 hours to ensure that the surface elevation of the pond is at least 184 feet above sea

level. The soundings confirm that, for this pond elevation, enough pond water volume exists for

the plant to safely shutdown and maintain long-term cooling.

Part of the acceptability criteria for the evaluation of the soundings is a curve (included in the.

LRA as Figure 4.5.1) showing the surface area of the pond versus the pond surface elevation,

based on the requirements of the UHS. This curve establishes a minimum acceptable volume

(with a margin) of 1325 acre-feet at a surface elevation of 184 feet. The applicant had validated

this curve by trending the rate of change of the volume of the pond using data from prior

surveillance soundings that are extrapolated to 40 years. For license renewal, the applicant

extrapolated the calculation to 60 years to validate the acceptability curve and to determine if an

update was necessary.

To extrapolate the'calculation for the period of extended operation, the applicant incorporated

surveillance data from soundings performed in 1993 and 1998. Data from an additional

surveillance performed in August 2003 were not available at the time the applicant submitted

the LRA. The calculation used the method of least squares to fit a curve through the data.

Based on the calculations that included the 1993 and 1998 data, the applicant stated that the

existing required pond volume remains conservative for the renewal term and adequately

assures that enough' pond water volume exists to achieve safe shutdown and maintain longterm cooling. Through this' review and the revision of the 'analysis, the applicant stated that it

has demonstrated that the TLAA is acceptable, as modified, for the renewed license term, in

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

4.5.1.2 Staff Evaluation

After reviewing the information contained in the LRA, the staff requested additional information

from the applicant. In RAI 4.5.1-1, the staff requested the applicant to provide the following

information:

4-32
Section 4.5.1 "Ultimate Heat Sink Silting" ofthe FNP LRA states that the applicant has

updated the design calculations pertaining to the surveillance of the Ultimate Heat Sink

(UHS) to address silting induced aging., It is further stated that this update addresses

the UHS silting issue for the additional 20 years of operations in the extended term in

accordance with 10 CFR 54.21 (c)(1)(ii).- In order to complete the review of the UHS

silting issue at FNP site; the staff needs the following additional information:

a. Provide the UHS pond volume surveillance data from all the available soundingmeasurement records to date. (Raw sounding measurements data are not required.)

b: Provide the rate of siltation of the UHS pond that was observed in the past based on

the periodic' surveillance measurements made thus far. Also address the applicability of

this measured rate to the remaining years of the current license period and the extended

period of operation (i.e., are there any known future changes in the hydrology of the

river likely to increase significantly sediment intake?) -

c. Explain briefly the procedure that was used to determine the observed and'projected

rates of siltation mentioned in item b above, and summarize the significant results

indicating the safety margin achieved in volume of water (acre-feet) in UHS.

The staff also met with the applicant on March 10,-2004, to discuss and clarify RAI4.51-1. :In

its response to RAI 4.5.1 -1 (a), dated April 16, 2004, the applicant provided the UHS pond

volume surveillance data from all the available sounding measurement records to date in a

tabular form, which included the data from the soundings made in August 2003. In its

responses to RAI 4.5.1 -1 (b) and (c), the applicant stated that the original calculation (before its

update for license renewal) used the sounding data taken in the years 1981 to 1989 to predict

the 40-year end of life (EOL) volume in the UHS.- The calculation used a linear regression

analysis and the'method of least squares to. plot a line through the data points. The slope of

this line can be used to estimate the siltation rate. The slope of the line for the original;

calculation implied a siltation rate of 0.6333 acre-feet per year, but the line and the data did not

correlate well. As a result, the predicted 40-year EOL volume in the UHS was reduced by 5

percent to 1325 acre-feet in the calculation. The applicant used the 1325 acre-feet value in the

evaluation of the service water pond as the UHS, as described in FSAR Section 9.2.5.

The calculation update for the LRA incorporated the additional sounding data from the 1993

and 1998 surveillance, using the same linear regression analysis method. Incorporation of the

additional data-resulted in a positive slope in the volume versus time curve. The applicant

calculated this'volume increase to be 0.772825 acre-feet per year. Using the line developed

from the analysis, the predicted 60-yearEOL volume in the UHS pond would be 1461 acre-feet.

However, the line and the data did not correlate well. Addition of the 2003 surveillance data led

to a smaller, but still positive slope in the curve. The volume increase with time is 0.054 acrefeet per year, with a predicted 60-year EOL UHS volume of 1421 acre-feet.

In summary, the applicant stated that the UHS pond surveillance data show minor-fluctuations

in the pond volume (both positive and negative) occurring over time with no siltation trend

indicated. -The updated calculation and surveillance data demonstrate that the UHS pond

volume during the period of extended operation will remain above the 1325 acre-feet used in

the UHS analysis.' 'The applicant further stated that the average operating conditions for the

UHS pond (inflow from the river, outflow, runoff flow, etc.) have remained consistent throughout

4-33
the current operating period. The applicant does not expect any changes in operating

conditions or the hydrology of the river that would lead to an increase in sediment intake. In

addition, the UHS'pond volume surveillance would identify any unusual change. -The average

measured pond volume (from the 12 sets of data taken over the last 22 years) is 1418.5 acrefeet, which results in a margin-of 7 percent above the 1325 acre-feet value used in the UHS

analysis. The minimum recorded UHS pond volume is 1403 acre-feet (from the 1984

surveillance data), which results in 5.8 percent margin over the UHS analysis value of 1325

acre-feet.

The staff performed an independent regression analysis of the data furnished by the applicant

and found that SNC's statements concerning the regression analysis were correct. Based on

this confirmatory'analysis, the staff concludes that SNC has demonstrated, through its revised

analysis of all available data, that its TLAA is acceptable for the renewed license term, in

accordance with i0 CFR 54.21 (c)(1)(ii). Therefore, the staff agrees with SNC's conclusion that

the existing required pond volume remains conservative for the renewal term and assures

adequate pond water volume to safely shutdown and maintain long-term cooling.

4.5.1.3 FSAR Supplement -

The applicant provided an FSAR Supplement summary description of its TLAA evaluation of the

UHS silting issue in Section A.4.5 of Appendix A to the LRA. On the basis of its review of the

FSAR Supplement, the staff concludes that the summary description of the applicant's actions

to address the UHS silting issue is adequate.

4.5.1.4 Conclusion

The staff has reviewed the applicant's TLAA of the UHS silting at FNP and concludes that the

applicant's actions and commitments satisfy the requirements of 10 CFR 54.21 (c)(1)(ii). The

staff has also reviewed the FSAR Supplement for the TLAA and finds that it contains a

description of the TLAA for the UHS sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.5.2 Leak-Before-Break Analysis

4.5.2.1 Summary of Technical Information in the Application

In Section 4.5.2 of the LRA, the applicant stated it had performed a leak-before-break (LBB)

analysis for the FNP primary coolant loop and the pressurizer surge line'. The LBB analysis

evaluated postulated flaw growth in the piping for the reactor coolant loops and the surge line.

The applicant stated that these analyses meet the definition of a TLAA.

For the primary loop, the applicant updated the LBB analysis to account for the period of

extended operation, in' accordance with 10 CFR 54.21 (c)(1)(ii).' The result of the update shows

that crack growth in the. lines is negligible, and that the environmental factor for reactor water

environments is not a significant parameter in the analysis. -

For the LBB analysis of the pressurizer surge line, the applicant determined that the current

analysis is bounding for 60 years, in accordance with 10 CFR 54.21 (c)(1)(i). The basis for this

conclusion is twofold-(1) the materials analyzed are not particularly susceptible to thermal

4-34
aging, so the calculation did not make a 40-year assumption regarding thermal aging, and (2)

the transient cycles assumed in the analysis are bounding for 60 years. , .i ..- .. . . , - i- O t -

In a supplemental letter dat6d October 9,2003, the applicant provided additional information

related to Section 4.5.2 of the LRA. The applicant performed plant-specific LBB analyses for'

both units of FNP which are summarized in'Section'3.6'of the FSAR.'These analyses provide

the technical justification for eliminating postulated breaks'in the'reactor-coolant loop (RCL).

piping (except for thfe'accarnumlator and RHR'branch connections) and pressurizer surge line

from the structural design basis. For the RCL,-W6stinghous'e performed an LBB analysis for

the FNP primary coolant loop under WCAP-1 2825, "Technical Justification for Eliminating Large

Primnary Lo'op Pipe' Rupture as the Design'Basis for the Joseph M. Farley Units 1 and 2 Nuclear

Power Plants," dated January 1991. The non-proprietary version of this document is WCAP- -

12826.:- The pressudrizer'surge line LBB analysis was -completed under WCAP-1 2835, - "Technical Justification for Eliminating Pressurizer Surge Line Rupture from the Structural

Design Basis for FNP Units 1 arid 2," dated;April 1991. -The non-proprietary version of this'

do uient is WCAP-12834. The staff accepted b6thtversions of the two LBB analyses on

April 12,1991, and Jariuary 15,1992, respectively:. : :

The applicant stated that the staff has approved both LBB analyses methodology and results.

(referring to the 1991 and 1992 approvals). The applicant stated that these analyses address

the aging effect of cracking. 'The applicant ierform'ed LBB crack stability evaluations for

enveloping critical locations, which were determined based on loading, pipe geometry, and

fracture toughness bonsiderations.' The applicant also carried out a fatigue crack growth

analjsis'to demonstrate that fatigue crack growth is -negligible. 'Assumptions in these analyses

having a potential basis in the original 40-year term of operation are fracture toughness

properties for cast austenitic stainless steel (CASS)'materials due to thermal aging

considerations and the cumulative cycles of design transients.

In a supplemental letter dated October 9, 2003, the applicant stated that it had performed a

TLAA evaluation of the 'primary loop and pressurizer surge'line LBB analyses. The applicant

stated that Westinghouse revised the RCLLBB analysis under.WCAP-12825 to account for the

additional thermal aging of the CASS materials for-the period of extended operation and issued

Addendu'm '1 to WCAP-1 2825 in December 2002. -The analysis accounts for the .effects of

thermrr'al'aging'degradation of the CASS materials due to 60 years of operation. Using faulted

loads, a margin of two'exists between the critical flaw and the flaw having a leak rate of 10-

gallons per minute. A margin of 10 exists between the calculated leak rate from the detectable

leakage flaw and the' FNP leak detection-capability of one gallon per minute. The applicant

stated that this meets the CLB,'as required by action item 10 of the NRC Final Safety:

Evaluation Rep6rtf6r WCAP-14575-A, in which 'a margin on loads of one is satisfied. No CASS

material for the FNP, Units 1 and 2,'primary loop piping has been replaced; therefore, the

second component of the action item is not applicable. , -

The applicant stated that an update of the'pressurizer surge line LBB analysis was required for

license renewal since the -surge line does'not contain CASS materials and since the transients

assumed for'40 years are bounding for 60 'years; as stated in Section 4.3 of the LRA. -The

applicant concluded that the analysis for the pressurizer surge line was reviewed and

determined to be 'acceptable as-is for the extended license term.- I '- .- .' !- ' -- - ,

i, : ', - ' '-).

4-35
4.5.2.2 Staff Evaluation

WCAP-1 2825 describes the application of LBB to the FNP, Units 1 and 2 RCS primary loop

piping. This report provides the technical basis for evaluating postulated flaw growth in the

main RCS piping'Under normal plus faulted loading conditions; The applicant performed LBB

crack stability evaluations' to envelop critical locations. The applicant also carried out a fatigue,

crack growth analysis for. a postulated flaw to demonstrate that fatigue crack growth was

negligible over 40 years. The staff concludes that this LBB analysis meets the definition of a

TLAA, as defined in Section 4.1 of NUREG-1800.

Since the primary loop piping contains cast stainless steel material, the thermal aging of theCASS material of the piping needs to be considered for the period of extended operation.

Pursuant to 10 CFR 54.21 (c)(1)(ii), the applicant projected the analyses to the end of the -

extended period by reanalysis. The applicant indicated that the analyses were revised, and

Addendum 1 to WCAP-1 2825 was issued in December 2002. According to the acceptance

criteria in Section 4.7.3.1.2 of NUREG-1 800, the staff must review the documented results of

the revised analyses to verify that their period of evaluation is extended such that they are valid

for the period of extended operation. The applicant offered no evidence that Addendum 1 was

approved, and therefore, the staff has not reviewed the acceptance criteria.

The staff asked the applicant in RAI 4.5.2-1 for the following information:

Section 4.5.2 of the application states that for the RCL, Westinghouse revised the.

WCAP-1 2825 analysis of the primary loop piping to account for the additional thermal

aging of the cast austenitic materials for the period of extended operation and issued

Addendum 1 in December, 2002. Please provide docketed evidence that Addendum 1

to WCAP-12825 was reviewed and approved by the staff. If there is no docketed

evidence, please submit the subject analysis for review.

By supplemental letter dated April 22; 2004, the applicant submitted both the proprietary and

nonproprietary versions of WCAP-1 2825, Addendum 1, "Technical Justification for Eliminating

Large Primary' Loop Pipe Rupture as the Structural Design Basis for the Joseph M. Farley Units

1 and 2 Nuclear Power Plants for the License Renewal Program." The staff noted that, in

accordance with 10 'CFR 50.59(c)(2)(viii), there was no departure from the evaluation method

described in the FSAR for establishing the design bases between the version of WCAP-1 2825

which was accepted by the staff on April 12; 1991, and WCAP,-12825, Addendum 1. In its.

updated LBB analysis, the applicant did not depart from the methodology previously approved

by the staff's April 12, 1991, safety evaluation: therefore, the staff concludes that the updated

LBB analysis of the RCS piping, which accounts for the thermal aging of CASS, assures that

the RCS piping will perform its intended function during the extended term, meeting the

requirements of 10 CFR 54.21 (c)(1)(ii). The staff finds this to be acceptable.

Since the V.C. Summer main coolant loop weld cracking event involving_ Alloy 82/182 weld

material, the staff has been addressing the effect of primary water stress-corrosion cracking.

(PWSCC) on Alloy 82/182 piping welds on a generic basis for all currently operating PWR

plants. To resolve this current operating issue, the industry is taking the initiative to (1) develop

overall inspection and evaluation guidance, (2) assess the current inspection technology, and

(3) assess the current repair and mitigation technology. An interim industry report, "PWR

Materials Reliability Project Interim Alloy 600 Safety Assessment for US PWR Plants (MRP-44),

4-36
Part 1: Alloy 82/182 Pipe Butt Welds,' was published in April 2001,-to justify the continued

operation of PWR plants while the industry completes the development of the final report. The

staff documented its acceptance of this interim report in a safetyevaluation issued June 14,

2001. The final industry report on this issue has not yet been published. Pending its receipt of

the final report and additional ultrasonic test (UT) inspection data from piping involving Alloy

82/182 weld material from the industry, the staff isworking towards resolution of this current

operating issue pursuant to 10 CFR Part 50.- Additionally, the staff issued RAI 4.5.2-1.

requesting the applicant to (1) identify the locations in the FNP RCS piping that contain Alloy

82/182 welds, and (2) describe actions it has taken to address this operating experience.

In its supplemental letter dated April 29,2004, the applicant stated that LRA Tables 3.1.2-1 'and

3.1.2-3 identify the Alloy 82/182 locations. The FNP RCS (ASME Class -1) piping Alloy 82/182

piping butt weld locations: are associated with RPV and pressurized nozzle-to-safe-end welds.

These locations include the following: - ., -;

-RPV primary inlet and outlet nozzle-to-safe-end welds(LRATable 3.1.2-1)

* pressurizer surge, safety (3 nozzles); relief, and spray nozzle-to-safe-end welds (LRA

Table 3.1.2-3)

The applicant stated that the FNP Alloy 82/182 pipe butt welds are characterized as high priority

safety significant welds and are volumetrically examined in accordance with the FNP Risk- -

Informed Inservice Inspection Plan requirements for ASME Code Examination Category B-F.

welds. The applicant performs its volumetric examinations in accordance with Section Xl of the

ASME Boiler and Pressure Vessel Code, as amended by 10 CFR 50.55a. Consistent with the

requirements of Appendix VilI to ASME Section Xl, examination techniques and personnel are

qualified through performance demonstration on realistic mockups. Implementation of

performance-based requirements has resulted in the development and application of improved

procedures for volumetric detection and characterization of PWSCC in pipe butt welds.

The applicant stated that visual examination of these weld locations for leakage continues'to'be

performed in accordance with ASME Code Examination Category B-P. In addition to these

inspection requirements, the Materials Reiiability Program (MRP) recommends that a direct;

visual inspection of the bare metal, or an equivalent alternative inspection, be performed once

within'the next two refueling outages. The applicant is currently implementing this'direct bare

metal visual examination. The welds on the pressurizer and the RPV will beyvisually examined

during the Unit 1 Fall 2004 outage. The six welds on the pressurizer, plus one of the RPV

'welds, were visually examined during the Unit 2 Spring 2004 outage with no problems noted.

The remaining five welds on theRPV will be visually examined during the Unit 2 Fall 2005

outage.' - . -

The applicant stated that long-term inspection requirements will most likely change in response

to new regulatory requirements from the NRC and industry recommendations from the MRP.

SNC is an active participant in the industry's efforts to resolve issues associated with PWSCC

of Alloy 82/182 pipe butt welds. After issuance and staff acceptance of a -final material reliability

program safety assessment for Alloy 821182 pipe butt welds, SNC intends to impl6reent the'

recommendations of this assessment at FNP.. Finally, the applicant stated that it reviews both

plant-specific and industrywide operating experience for applicability to' FNP. :Theappiicanif

would further evaluate any applicable events for their potential impact at FNP. 'The staff

4-37
I

concludes that the applicant's involvement in current industry programs, as well as its interim

inspection of All6y 82/182 welds in accordance with ASME Appendix VIII, provides reasonable

assurance that the RCS pipinig will perform its intended function during the extended term, thus

meeting the requirements of 10 CFR 54.21 (c)(1)(ii), and is, therefore, acceptable.

The applicant also completed a TLAA evaluation of the pressurizer surge. line LBB analyses.

The applicant determined that the pressurizer surge line LBB analysis did not require updating

for the LRA because the surge line does not contain CASS materials. In addition, the

transients assumed in the analysis for 40 years are bounding for 60 years. Because the

number of cycles of fatigue the pressurizer surge line experiences during the extended term is

used to bound the LBB analysis, the staff concludes that this LBB analysis meets the definition

of a TLAA, as described in Section 4.1 of NUREG-1800.

Table 4.3.1 of the LRA indicates the current number of cycle counts and the projected

maximum allowable number of cycle counts at 60 years of plant operation for transients in the

design of Class 1 components. In RAI 4.3.1-1, the staff requested that the applicant describe

the method that it will use to estimate the number of transient cycles that occurred prior to the

installation of the fatigue monitoring software and to provide a list of transients that will be

monitored by the fatigue monitoring program. This RAI resulted from the staff's review of the

applicant's fatigue TLAA. Section 4.3 of this SER includes the staff's review of the applicant's

response to this RAI.

4.5.2.3 FSAR Supplement

The applicant provided an FSAR Supplement summary description of its TLAA evaluation of the

LBB analysis in Section A.4.6 of Appendix A to the LRA. On the basis of its review of the FSAR

Supplement, the staff concludes that the summary description of the applicant's actions to

address the LBB analysis is adequate.

4.5.2.4 Conclusion

The properties for the CASS piping material are acceptable because they will not degradebelow the fully aged properties in the extended period of operation.- The applicant has

established a fatigue monitoring program to assure that the number of cycle counts for a

transient set do not exceed its cycle limits. With respect to the potential for PWSCC of Alloy

82/182 welds, the staff is working towards resolution of this current operating issue pursuant to

10 CFR Part 50. Any measures to be implemented, or any requirements to be imposed, as part

of the resolution of the PWSCC issue under 10 CFR Part 50, will also apply during the period of

extended operation. Therefore, the staff concludes that the applicant has provided an

acceptable TLAA regarding LBB and meets the requirements of both 10 CFR 54.21 (c)(1 )(i) and

10 CFR 54.21(c)(1)(ii).

4.5.3 Residual Heat Removal Relief Valve Capacity Verification Calculations

4.5.3.1 Summary of Technical Information in the Application

In Section 4.5.3 of the LRA, the applicant took credit for the relief capacity of the RHR relief

valves in the cold overpressure mitigation analysis for FNP, Units 1 and 2. The applicant has a

4-38
calculation that verifies relief valve capacity given the safe-operating pressure and temperature

limit curves. The calculation adjusts the P-T limit curves to account for the flow-induced

pressure drop from the beltline of the RV to the RHR relief valves. This calculation currently

evaluates changes to P-T limit cuives for 16, 24, 36, and 48 EFPYs. Because the applicant is

evaluating the P-T limit curves for 54 EFPYs to support license renewal, the applicant stated

that it will update this analysis to include the calculated 54-EFPY P-T limit curves before

entering the PEO.

4.5.3.2 Staff Evaluation

Cold overpressure mitigation in FNP, Units 1 and 2, is accomplished using the RHR relief

valves. The calculation verifies the relief capacity of the RHR valves. The applicant used the

methodology described in the FSAR and will update the calculation at the time the license

extension becomes effective. The staff finds the methodology and the applicant's commitment

to update the RHR relief capability for the P-T curves in effect at the time the license extension

becomes effective to be acceptable.

4.5.3.3 FSAR Supplement

The applicant provided an FSAR Supplement summary description of its TLAA evaluation of the

RHR relief valve capacity verification calculations in Section A.4.7 of Appendix A to the LRA.

On the basis of its review of the FSAR Supplement, the staff concludes that the summary

description of the applicant's actions to address RHR relief valve capacity verification

calculations is adequate.

4.5.3.4 Conclusion

The staff has reviewed the applicant's TLAA of the RHR relief valve capacity verification

calculations at FNP, Units 1 and 2, and concludes that the applicant's actions and commitments

satisfy the requirements of 10 CFR 54.21 (c)(1)(ii). The staff has also reviewed the FSAR

Supplement for the TLAA and finds that the FSAR Supplement contains a description of the

TLAA for the RHR relief valve capacity verification calculations sufficient to satisfy the

requirements of 10 CFR 54.21 (d).

4.6 Conclusion for Time-Limited Aging Analyses

The staff has reviewed the information in Section 4, "Time-Limited Aging Analysis," of the LRA.

On the basis of its review, the staff concludes that the applicant has provided an adequate list

of TLAAs, as defined in 10 CFR 54.3. Further, the staff concludes that the applicant has

demonstrated that (1) the TLAAs will remain valid for the period of extended operation, as

required by 10 CFR 54.21 (c)(1)(i), (2) the TLAAs have been projected to the end of the period

of extended operation, as required by 10 CFR 54.21 (c)(1)(ii); or (3) the aging effects will be

adequately managed for the period of extended operation, as required by

10 CFR 54.21 (c)(1)(iii). The staff has also reviewed the FSAR Supplement for the TLAAs and

finds that the FSAR Supplement contains descriptions of the TLAAs sufficient to satisfy the

requirements of 10 CFR 54.21(d). In addition, the staff concludes that no plant-specific

exemptions are in effect that are based on TLAAs, as required by 10 CFR 54.21©)(2).

4-39
5. REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

On October 15, 2004, the U.S. Nuclear Regulatory Commission staff (the staff) issued its draft

safety evaluation report (SER) related to the renewal of operating licenses for the Joseph M.

Farley Nuclear Plant (FNP), Units 1 and 2. In accordance with Title 10, Part 54, of the Code of

Federal Regulations (10 CFR Part 54), the Advisory Committee on Reactor Safeguards (ACRS)

is reviewing the license renewal application (LRA) for FNP, Units 1 and 2. On November 3,

2004, the applicant presented its LRA, and the staff presented its review findings as contained

in the draft SER, to the ACRS Plant License Renewal Subcommittee. On November 30, 2004,

the applicant provided comments to the staff's draft SER. The staff reviewed the applicant's

comments. On March 3, 2005, the staff completed its review of the LRA and issued its SER

related to the license renewal of the FNP, Units 1 and 2.

During its 521 st meeting held on April 7, 2005, the ACRS Full Committee on Plant License

Renewal completed its review of the FNP, Units 1 and 2, LRA and the staff's SER. The ACRS

documented its findings in a letter to the NRC Chairman dated April 14, 2005. A copy of this

letter is provided on the following pages of this SER Section.

5.-1
April 14, 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 JOSEPH M. FARLEY NUCLEAR PLANT,

UNITS 1 AND 2

Dear Chairman Diaz:

During the 521 s' meeting of the Advisory Committee on Reactor Safeguards (ACRS), April 7-8,

2005, we completed our review of the license renewal application for the Joseph M. Farley

Nuclear Plant (FNP), Units 1 and 2, and the related final Safety Evaluation Report (SER)

prepared by the NRC staff. Our Plant License Renewal Subcommittee also reviewed this

matter during a meeting on November 3, 2004. During our review, we had the benefit of

discussions with representatives of the NRC staff and Southern Nuclear Operating Company,

Inc. (SNC). We also had the benefit of the documents referenced. This report fulfills the

requirement of 10 CFR 54.25 that the ACRS review and report on all license renewal

applications.

CONCLUSIONS AND RECOMMENDATIONS

1. The programs established and committed to by the applicant will provide reasonable

assurance that FNP 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 SNC application for renewal of the operating licenses for FNP Units 1 and 2 should

be approved.

BACKGROUND AND DISCUSSION

FNP Units 1 and 2 are 2775 MWh, three-loop Westinghouse pressurized water reactors housed

in pre-stressed/post-tensioned dry containment buildings. SNC requested renewal of the units'

operating licenses for 20 years beyond the current license terms, which expire on June 25,

2017, for Unit 1, and March 31, 2021, for Unit 2.

In the final SER, the staff documents its review of the license renewal application and other

information submitted by SNC and obtained during the audits and inspections conducted at the

5-2
plant site. The SER also includes commitments identified by the staff and agreed to by the

applicant. The staff reviewed the completeness of the applicant's identification of structures,

systems, and components (SSCs) that are within the scope of license renewal; the integrated

plant assessment process; the applicant's identification of the plausible aging mechanisms

associated with passive, long-lived components;' the adequacy of the 'applicant's aging

management programs; and the identification and assessment of time-limited aging analyses

(TLAAs) requiring review.-

The FNP application either demonstrates consistency with the Generic Aging Lessons Learned

(GALL) Report, or documents deviations to the specified approaches in the GALL Report. The

FNP application is the first to be evaluated using a new audit and review process intended to

confirm co'risistency with'the GALL Report, ai6d the acceptability of deviations from that report.

This approach, which requires more review activities at the site, has resulted in improved

communications and more effective interactions between the applicant and the staff, and a

significant reduction in requests for additional information. During our meeting,-the staff

presented a well-structured and effective overview of its reviews, audits, and inspections.

Several scoping issues that in previous applications resulted in significant disagreement

between the staff and applicants were promptly resolved at FNP due to the clear interim staff

guidance. Among these issues were fuse holders,--equipment required to recover from station

blackout, and fire protection equipment. The staff disagreed with SNC in some areas,-such as

the scoping criteria' for spray interactions in low-energy lines. We agree with the resolution of

these issues, and the staff and SNC should be commended for promptly resolving them. -

The applicant performed a comprehensive aging management review of all SSCs within the

scope of license renewal. In the application,-SNC describes 22 aging management programs

for license renewal including existing, enhanced, and new programs. -We agree that these

programs are adequate.

We reviewed plant-specific operating experience to assess how effectively the applicant has

dealt with age-related degradation. 'In 1987, FNP Unit 2 experienced a throughwall leak in an

unisolable portion of the'emergency core cooling system piping. The leak was attributed to

thermal cycling due to-valve leakage. This event led to the issuance of NRC Bulletin 88-08,

"Thermal Stresses in Piping Connected to the Reactor Coolant System." Since then, FNP has

established accurate baseline cycle counts. For license renewal, the applicant developed a

new fatigue monitoring program consistent with the GALL Report for monitoring fatigue of metal

piping in components of the reactor coolant pressure boundary. The program will automatically

monitor cycles using installed plant equiprment.

As in previous reviews, we questioned the adequacy of opportunistic inspections of inaccessible

buried piping and tanks, in lieu of periodic inspections at a plant-specific frequency, as specified

in the GALL Report. The applicant has committed to enhancing its Buried Piping and Tank

Inspection Program by performing an inspection within 10 years of entering the period of

extended operation unless an opportunistic inspection has occurred within this 1 0-year period.

This program enhancement is appropriate. The staff has also included this 1 0-year inspection

as new generic guidance in the proposed revision to the GALL Report.

The applicant has also committed to perform an engineering evaluation before the 1 0' year of

extended operation to determine whether sufficient inspections have been conducted to draw a

5-3
conclusion regarding the ability of the coatings to protect underground piping and tanks from

degradation. If not, a focused inspection will be conducted to allow a conclusion to be reached.

We agree with the staff that the applicant has identified and properly addressed systems and

components requiring TLAAs. The staff has independently verified the applicant's calculations

of reactor vessel upper shelf energy and has confirmed that the limiting beltline materials at 60

years satisfy the acceptance criteria. We also note that the most limiting beltline materials

satisfy the pressurized thermal shock criterion with ample margin based on both the applicant's

and the staff's calculations.

When environmental factors are applied and projected to 60 years, cumulative usage factors

(CUFs) for some piping locations may exceed a CUF of 1.0. For these locations, the applicant

has committed to take corrective action prior to the period of extended operation. This action

might include a more refined analysis, repair, replacement, and/or an inspection program

approved by the NRC. We are satisfied with this commitment.

The licensee is improving FNP Units 1 and 2. New steam generators with Alloy 690 tubing,

quatrefoil support plates, and full depth rolls were installed in both units in 2000 and 2001.

Although control rod drive mechanism (CRDM) inspections have not identified leaks, both units

are susceptible to CRDM cracking due to high head temperatures. Therefore, reactor vessel

heads are being replaced with new heads that contain Alloy 690 penetrations without thermal

sleeves. The licensee has also replaced the cooling towers and installed a dry cask storage

facility.

Recent inspections of the reactor pressure vessel lower head penetrations of both units

revealed no degradation. Bare metal visual inspections of Alloy 600/182/82 pressure boundary

locations were also performed and did not reveal any degradation.

We agree with the staff that there are no issues related to the matters described in 10 CFR

54.29(a)(1) and (a)(2) that preclude renewal of the operating licenses for Farley Units I and 2.

The programs established and committed to by SNC provide reasonable assurance that the

plant can be operated in accordance with its current licensing basis for the period of extended

operation without undue risk to the health and safety of the public. The SNC application for

renewal of the operating licenses for FNP Units 1 and 2 should be approved.

Sincerely,

/RAN

Graham B. Wallis

Chairman

5-4
References

1. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License

Renewal of the Joseph M. Farley Nuclear Plant, Units 1 and 2," March 2005

2. Southern Nuclear Operating Company, Inc. "Joseph M. Farley Nuclear Plant License

Renewal Application," September 2003

3. U.S. Nuclear Regulatory Commission, "Draft Safety Evaluation Report Related to the

License Renewal of the Joseph M. Farley Nuclear Plant, Units 1 and 2," October 2004

4. U.S. Nuclear Regulatory Commission Inspection Report 50-348/2004-007, 50-364/2004-

007, Scoping and Screening, June 22, 2004

5. Information Systems Laboratories, Inc., "Audit and Review Report for Plant Aging

Management Reviews and Programs, Joseph M. Farley Nuclear Plant, Units 1 & 2,"

September 10, 2004

5-5
6. CONCLUSIONS

The staff of the U.S. Nuclear Regulatory Commission (NRC or the Commission) reviewed the

license renewal application for the Joseph M. Farley 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," dated July 2001. Title 10, Section

54.29, of the Code of Federal Regulations (10 CFR 54.29) provides the standards for issuance

of a renewed license.

On the basis of its evaluation of the license renewal application, the NRC staff has determined

that the requirements of 10 CFR 54.29(a) have been met.

The staff notes that the requirements of Subpart A of 10 CFR Part 51 regarding the Joseph M.

Farley Plant, Units 1 and 2, are documented in Supplement 18 to NUREG-1437, "Generic

Environmental Impact Statement for License Renewal of Nuclear Plants: Regarding Joseph M.

Farley Nuclear Plant, Units 1 and 2, Final Report," published in March 2005.

6-1
APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL

During the review of the Joseph M. Farley, Units 1 and 2, LRA by the NRC staff, the applicant made commitments related to aging

management programs (AMPs) to manage aging effects of structures and components' (SCs) during the period of extended

operation. The'following table lists these commitments, along with the implementation schedule and the source of the commitment.

.J t:. : , ,p ;.e.t.t.o. . NO. HI I S- 2 i i Ippbndlx AW *:7~SIi~~f

1 The Flow Accelerated Corrosion (FAC) Program will be A.2.8 Prior to entering the LRA App B,

enhanced'prior to entering' the exended period of period of extended Section B.4.1

operation by adding the auxiliary feedwater pump turbine operation

exhaust piping to the, scope of the program.

2 An evaluation of the Diesel Fuel Oil Chemistry Control A.2.9 Prior to entering the LRA App. B,

Program scope6 and the need to im'prove--procedural'x period of extended Section B.4.2

guidance for rm'aintaining and monitoring the diesel driven operation

fire pump fuel oil system will be'performed and any

necessary changes implemented prior to the period of

extended operation. '

A-1
,!- 2Commg.ltment, H LRA ipX Eemento Sorce V No~~c • '~~' ~ ~Appendlx 1A- ________

3 The Structural Monitoring Program will be enhanced prior A.2.10 Prior to entering the LRA App. B,

to entering the period of extended operation to include period of extended Section B.4.3

portions of structures and components which are in scope operation

for license renewal but are not currently monitored. These

additional structures and components include:

* submerged portions of the Service Water Intake

Structure (SWIS),

* in-scope support features for ATWS, SBO, and fire

protection safe shutdown equipment in the Turbine

Building,

* structural portions of the Oil Static Pump House,

* in-scope components in the Low Level Radwaste

Building and Solidification/Dewatering Building

(e.g., fire protection).

An enhancement will be made to the Structural Monitoring

Program document to clarify the hangers and supports to

be inspected in Category I buildings.

4 The scope of the Service Water Program will be expanded A.2.1 1 Prior to entering the LRA App. B,

prior to the period of extended operation to include period of extended Section B.4.4

inspection of piping from the main service water header to operation

the air compressor credited for Appendix R safe shutdown

and inspection of the service water pump columns.

A-2
No." ,IR irCpemetalonme rstIce ~, otminndI A :IScled~ii

5 The FNP Fire Protection Program will be enhanced prior to

entering the period of extended operation (with the

exception of sprinkler head testing which will be

implemented prior to 50 years of fire protection system

service) as follows:

:The fire protection sprinkler system piping will be

subjected to wall thickness evaluations (e.g.,

non-intrusive volumetric testing and/or visual

inspections during plant maintenance) prior to the

'period of extended operation and at specific

, intervals thereafter.. The plant-specific inspection

interval will be established fromr'the initial inspection

results and revised as appropriate for subsequent

inspection results.

A sample of sprinkler heads will be inspected by

using the guidance of National Fire Protection

Association (NFPA) 25 (2002), Section 5.3.1.1.1, at

or before 50 years service and every 10 years

thereafter.

* Diesel driven fire pump surveillance procedures will

be upgraded to provide more detailed instructions

related to inspection of,the fuel'oii supply piping.

*, The' current practice of replacing C02 hoses'at 5

7, year intervals will be formalized in fire protection

'procedures.

A.2.12 Prior to entering the

period of extended

operation (with the

exception of sprinkler

head testing which

will be implemented

prior to 50 years of

fire protection system

service)

J -

LRA App. B,

Section B.4.5

4-.

.,I

i1

I -. A-3
I S

No, /Y.- App iA'LA | S

6 The new FNP Reactor Vessel Internals (RVI) Program will A.2.13 Program LRA App. B,

be implemented prior to entering the period of extended implementation: Prior Section B.5.1

operation to provide an integrated inspection program that to entering the period Letter NL-04-0715

addresses the reactor internals. It will supplement the of extended operation pg E2-13, E2-15

inspection requirements of ASME Section Xl,.IWB

Category B-N-3 to ensure that aging effects do not result in Participation in

a loss of intended function of internal components during industry initiatives:

the period of extended operation. Ongoing Activity

SNC will continue to participate in industry initiatives Submittal of

intended to clarify the nature and extent 'of aging inspection plan: At

mechanisms potentially affecting the FNP reactor internals. least 24 months prior

SNC will incorporate the results of these initiatives into the to entering the period

RVI Program. of extended operation

for the FNP unit

FNP will submit an inspection plan for the RVI Program for

NRC review and approval at least 24 months prior to

entering the periods of extended operation for the FNP

units.

The RVI Program will be consistent with the NUREG-1 801

Programs XI.M13 and XI.M16, except as described above.

A-4
!'eL 1s;. KJSource' 

7 The new Flux Detector Thimble Inspection Programwill be A.2.14 Prior to entering the LRA App. B,

implemented prior to entering the period of extended period of extended Section B.5.2

operation to formalize examinations already being operation

performed. It will be used to identify loss of material due to

fretting/wear in the- detector thimbles during the extended -

period of operation.

The program will include flux detector thimbles for both.

units. .lt does not include the instrument guide tubes,

which are covered underthe IS Program and the Reactor

Vessel Internals Program. ' -

8 The new6 Exte'rnalSurface6s Monitorririg Program will be' A.2.15 Prior to entering the LRA App. B,

irmp embnted prior to entering thei perioddof exte'nded'tperiod of extended Section B.5.3

operation.'e 1 *' i i' ' operation

: i:\. Letter NL-04-0924

The FNP External Suifaces Monitoring Program will'. pg E2-4;

employ periodic visual inspections to manage accessible

and insulated external surfaces susceptible to loss of Letter NL-04-0678

material that require6aging 'management for license pg E2-4

renewal.; Susceptible 'external surface's include carbon

steel and low alloy steels in inside and outside

environments, and galvanized steel, cast iron, copper

alloys, and aluminum in an outside environment.

The FNP External Surfaces Monitoring Program Is also

credited for managing loss of uimaterial, cracking, and

change in material properties In elastomers within the ' scope of th66program.'

A-5
;. '..1. LaN n..1 . ______________________________________ ;WpendlWx.A A- Schedulie-,.14.

9 The new Buried Piping and Tank Inspection Program will A.2.16 Prior to entering the LRA App. B,

be implemented prior to the period of extended operation. period of extended Section B.5.4

This program will be consistent with NUREG-1 801 operation

Program XI.M34,'with the exception that it also'includes Letter NL-04-0473

provisions for inspection of buried stainless steel and pg E1-23

copper alloy piping.

Letter NL-05-0340

This program will be used to manage loss of material from

the external surfaces of in-scope pressure-retaining buried

carbon steel piping and tanks, as well as buried stainless

steel and copper alloy piping components. Buried piping

and tanks within the scope of the program will be inspected

when they are excavated for maintenance or when those

components are exposed for any reason. SNC will

perform an inspection of buried piping and tanks within ten

years after entering the period of extended operation,

unless an opportunistic inspection has occurred within this

ten-year period. 'Before the tenth year, SNC 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 and tanks from degradation. If not,

SNC will conduct a focused inspection to allow that

conclusion to be reached.

A-6

a
LRA- All$5t"i 'I ' 'b

10 The new One-Time Inspection (OTI) Program will be A.2.17 Inspections to be LRA App. B,

implemented prior to the period of extended operation. completed prior to Section B.5.5

The One-Time Inspection Program will include measures entering the period of

to verify the effectiveness of various other aging extended operation Letter NL-04-0924

management programs and confirm the absence of aging (as noted in the pg E2-11

effects. Insofar as practical with respect to scheduled commitment)

outages, the inspections will be performed within a window Letter NL-04-0318

of five'years'immediately preceding the period of extended pg E-17 & 19

operation. This program will be consistent with the aging

management programs described in NUREG-1 801 XI.M32

'and Xi.M33.; , *;-

'Specific Components Included in OTI Sample Population.,

* Pressurizer cast austenitic stainless-steel spray , heads and associated cou lose spry upllng/,lock bar,,.,,,

* Examination of Reactor coolant system small bore

(<4-inch NPS) ASME Class 1 piping components,

consistent with NUREG-1 801 Section XI.M32

requirements, to address NRC concerns regarding

cracking due to SCC or thermal cycling. This.

examination will also serve as an indicator of the

potential for SCC in other stainless steel

components exposed to a borated water,,

environment ! ;

* An RCP thermal barrier CCW nozzle

* Cast iron, bronze, brass and other'alloy'

components in any system requiring aging.

.management that are exposed to environments that.

. _ may lead to selective leaching

A-7
. . .. . .

No.K5 4~~Appendix-A ~ Shdle~2"W

10 * A bounding CVCV letdown orifice or charging/SI

cont'd pump miniflow orifice (based on pressure drop)

* Sample portion of the external surface of the

service water piping in the Diesel Generator

Building which is obscured by guard piping

* TDAFWP lube oil coolers (fouling of the tubes in a

lube oil environment).

* U-1 Condensate Storage Tank bottom (thickness

measurement)

General LRA Systems In-Scope:

The OTI Program will select and inspect representative

locations from the general LRA systems based on the

applicable materiaVenvironment/aging effect combinations

(as specified in the LRAand docketed correspondence) to

confirm an aging effect does not require management and

verify aging management program effectiveness. Alloy

steel steam/fluid traps in a steam and treated water

environment will be included in the scope of the OTI

Program.

A-8
4 - ppendixA. 2 -- w Comten . ?;9, .2i Hot .uco

11 The plant-specific NiCrFe Component Assessment A.2.18 Program LRA App. B,

Program will be implemented prior to the period of implementation: Prior Section B.5.8

extended operation. The program scope will include nickel to entering the period

base alloy reactor coolant pressure boundary components of extended operation Letter NL-04-0715

with known or potential susceptibility to primary water pg E1-6

stress corrosion cracking (PWSCC), excluding steam Participation in

generator tubes, which are specifically addressed by the industry initiatives: Letter NL-04-0967

Steam Generator Program, and Reactor Internals which Ongoing Activity pg E-6

are addressed by the Reactor Vessel Internals Program.

Submittal of

SNC Wil continueito p'articipate in industry Initiatives (such inspection plan: At

as the' We'stingfi0use Owners Group~ and EPRI Materials least 24 months prior

Reliability:Pr6grarm)., Susceptibility ranking and prog'ram to entering the period

inspection requirements will be consistent'with the latest of extended operation

version6 of the EPRI Materials'Reliabilit Program' safety for the FNP unit

assessment regarding Alloy 82/ 182 pipe butt welds or its . .. s~ . -.- ., - .-.. 

successors. .

FNP will submit arn inspection plan for the NiCrFe'

Component Assessment Program for NRC review and

approval at least 24 months prior to entering the periods of

extended operation for the FNP units. '

A-9
ter Ir~~#G~Ii on,,,:.,.-.;.'I ~ ource'

12 FNP will implement the new Non-EQ Cables and A.2.19 Prior to entering the LRA App. B,

Connections Program. The Non-EQ Cables and period of extended Section B.5.6

Connections Program consists of two parts. operation

Letter NL-04-0678

The first part addresses non-EQ electrical cables and pg E1-18

connections used in circuits with sensitive, high voltage,

low-level signals such as radiation monitoring and nuclear

instrumentation.; An AMP designed specifically for these

types of cables will be implemented as an alternate

program to the XL.E2 program described in NUREG-1 801.

All in-scope instrument circuit cables with sensitive, high

voltage, low-level signals which are installed in adverse

localized environments will be tested.

The other part addresses non-EQ'electrical cables and

connections exposed to adverse localized environments

caused by'heat, radiation, or moisture and inaccessible

medium voltage cables that are simultaneously exposed to

significant moisture and voltage. This program section will

be implemented consistent with NUREG-1 801 programs

XL.E1 and XL.E3. ' '

A-10
.7 -I -. 1~. . , - f .-1- ~ . ~ . , ~ , ,T ,. e. " 1. ~ ~I . * - r~I. 11e

Item .~ ~ ~ ~ ~ ~ ~LRA 'mplementatlobhp. "*...- QSure 

13 The FNP Fatigue Monitoring Program will be fully . A.3.2 ,Prior to entering the LRA App. B,

implemented consistent with NUREG-1 801 Program X.M1 period 6f extended Section B.5.7

prior to the period of extended operation. The Fatigue operation

Monitoring program will be used to monitor fatigue

conditions of the metal piping and components that form

the reactor coolant pressure boundary (RCPB).,

Specifically included will be the pressurizer

subcomponents, the RPV shell and head, RPV inlet and

outlet nozzles, reactor coolant piping, charging nozzles,

safety injection nozzles and the other Class 1 piping

one-inch in diameter or larger. The other Class 1 :*

components that have received a fatigue analysis will also

be included, since the cycles they were designed for are

bourded by th"e''c616iimit'iused ythe"progra''m. ' WhI6f l-d.., I O

When fully implenented, the program wil inciude: A *-;.

* Cycle Counting - Plant transients that are significant

contributors to the fatigue cumulative usage factor

will be monitored'and counted;

* ,Thermal stratification monitoring - susceptible

locations (NRC Bulletin 88-08) will be monitored;

* . Stress-based fatigue monitoring of the surge line

and lower region of the pressurizer (includes

thermal stratification and insurge/outsurge effects).

: i

-.

A-11
* Item Commit ~ ~IRA 4R. '

~:Ap4d:x'A: mpde Sc u Ittln :j Suc3⁄4

14 The application of the appropriate environmental factors to A.4.2.1 Prior to entering the LRA Section 4.3.1

the calculations for the following locations resulted in an period of extended

environmentally-assisted fatigue adjusted value greater operation

than 1.0.' For the locations listed below, SNC will take

corrective action prior to the period of extended operation

which might include a more refined analysis, repair,

replacement, and/or an inspection program approved by

the NRC.,

* Charging nozzles and alternate charging nozzles

* RHR 6-inch RHR/SI nozzles to the Reactor Coolant

System cold leg.

15 SNC will update the RHR Relief Valve Flow Capacity A.4.7 Prior to entering the LRA Section 4.5.3

analysis that utilizes P/T curves as an input to include the period of extended

calculated 54 EFPY P/T Limit Curves prior to the period of operation

extended operation. l -

16 Prior to the period of extended operation FNP will collect N/A Prior to entering the LRA Section 4.3.1

data for transients (pressurizer heat-up, small step period of extended

increase/decrease in load of 10% full power per minute, operation

and large step increase in load) not counted prior to the

installation of the fatigue monitoring software and use the

data to develop a best estimate historical count and an

expected 60-year count.

17 FNP will use the NUREG-1437 Supplemental Appendix D Prior to entering the LRA App. D

Environmental Impact Statement for Farley Nuclear Plant period of extended

along with the original Farley Environmental Impact operation

Statement as the basis for any environmental reviews

performed during the renewal term.

A-12
MMrii Cmime LA rnp e'mpeientlh: 2' Sou rce

- iAppenrdix "A : . .,

18 Reactor Vessel Surveillance Program: N/A Prior to operation LRA App. B,

after removal of the Section B.3.4

For each unit, FNP will install alternative dosimetry to last surveillance (and consistency

monitor neutron fluence on the reactor vessel after removal capsule in that unit with NUREG-1 801

of the last surveillance capsule in that unit. Section XL.M31)

After all surveillance capsules have been removed, the

exposure conditions of the reactor vessel will be monitored

to ensure consistency with those used to project the effects

of embrittlement to the end of the license period. Any plant

operating restrictions (on parameters such as inlet .

temperature, neutron flux,. etc.) will be determined. The

program will include provisions that if reactoryvessel

exposure conditions are altered such that'analysis

assumptions could be invalidated, appropriate actions will

be performed (e.g., re-evaluation, re-instituting an active

surveillance program, notifying the NRC, etc.) to assure

the adequacy of the projection to the end of the license

period. -

A-13
<Item _mwlee LA . -No; - ~- AppedixW A kJSchedule~X4:~~

19 SNC will submit the following information on the Unit 1 flux N/A After the second Letter NL-04-1096

thimble tubes (after the second inspection of the new tube inspection (during pg E-5

materials during Ul R20): U1 R20 in 2006) and

wear projection

* The worst case cumulative wear from the Ul R20 analysis is completed

flux thimble tube eddy current inspection.

* The uncertainty applied to the actual measured

wear data.

* The thimble tube wall thickness.

* The schedule for the'next Unit 1 flux thimble tube

inspection,(inspection interval).

* The projected wear value for the worst case wear

location at the end of the next inspection interval.

* A discussion of the technical basis for establishing

the Unit 1 inspection interval that will be

implemented after performing the, U1 R20 flux

thimble tube eddy current inspection of the new

tube materials. The discussion will address the use

of the equation in Proprietary WCAP-12866 and the

unit-specific wear data in projecting the wear to the

next inspection outage. The curve coefficient (i.e.,

exponent 'n'). used in the projection of flux thimble

tube wear will be provided.

A-14

. . ... ..... ... .. . .;.. . ....... ...... ... ........ ....... _
..tem: -b- Item~ ~ rTCig ,~. ~ fih;u- 1 tftibhi ~*~ @.s, -. RA )l . - dipkentatIoni,~ oucurc;

o;s.;t<.. .I, - .* 'A

20 The following Periodic Surveillance and Preventive A.2.20 Prior to entering the Letter NL-04-1038

Maintenance Activities credited for license renewal are to (provided in period of extended pg E-8 to E-1 1

be implemented prior to the period of extended operation: NL-04-1038 operation (new LRA Section

pg E-8) B.5.9)

* Boric Acid Tank Diaphragms Inspections

* Reactor Makeup Water Storage Tank Diaphragms

Inspections

-* Condensate Storage Tank Diaphragms Inspections

A-15
: APPENDIX B:. CHRONOLOGY

This appendix contains a chronological listing of the routine licensing correspondence between

the U.S. Nuclear Regulatory Commission " (NRC) stiff and the Southern Nuclear Operating

Company (SNC), and other correspondence regarding the NRC staff's reviews of the

Joseph M. Farley'Ndclear Plant (FNP),' Units 1 and 2 (under Docket Numbers 50-348 and

50-364) license renewal application (LRA).

September 12, 2003 In a letter, NL-03-1657 (signed by J. Beasley, Jr.), SNC submitted its LRA

for the Joseph M. Farley Nuclear Plant, Units 1 and 2. ML032721353 -

September 30, 2003 In a letter (signed by P.'Kuo), NRC informed SNC of the receipt of the

LRA for FNP Units 1 and 2 and Tilda Liu will be the PM for safety review

and Jack Cushing will be PM for environmental review. 'ML032731456

October 1, 2003 In a memorandum (signed by T. Liu), NRC summarized the September

23, 2003 meeting between the'NRC staff iand SNC to discuss the FNP

LRA. ML032760306

October 8, 2003 In a memorandum (signed byJ.: Funches), NRC granted a partial fee

waiver for FNP's LRA.' -ML032820040

October 9, 2003 In a letter, NL-03-2098 (signed by J. Beasley, Jr.), SNC submitted

expanded information on Section 4.5 of LRA related to Time Limited

Aging Analysis. ML032870360

October 24, 2003 In a letter (signed by P. Kuo), NRC informed SNC the LRA was accepted

and sufficient for docketing and proposed review schedule.

-- ML032970522'

October 29, 2003 In a letter (signed by T. Liu), NRC provided SNC a revised schedule for

the conduct of review for FNP. 'ML033030051

October 30, 2003 In a letter (signed by P. Kuo), NRC issued notice of opportunity for

' hearing for the LRA for'FNP.' ML033040243';

December 2, 2003 In a memorandum (signed by T. Liu), NRC summarized the October 27,

2003 conference call between the NRC staff and SNC regarding draft

Request for Additional Inf6rmation (RAI) concerning the staff's review of

the LRA.' ML033390305 - -

December 5, 2003 In a letter, NL-03-2418 (signed by J. Beasley, Jr.), SNC provided NRC

supplemental information and 'a future action commitment list regarding

the LRA. 'ML033430278'

December 12, 2003 In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerhin its review of the LRA. ML033520279

B-1
December 12, 2003 In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML033520302

December 23, 2003. In a letter (signed by T. Liu), NRC provided SNC a revised schedule for

the conduct of the NRC's review of the LRA. ML033580545

January 9, 2004 In a letter, NL-04-2623 (signed by L. M. Stinson), SNC provided a

response to NRC concerning RAls related to the staff's review of the

LRA. ML040150414

January 9, 2004 In a memorandum (signed by T. Liu), NRC summarized the December 3,

2003 conference call between the NRC staff and SNC to discuss SNC's

proposed responses to draft RAIs concerning the LRA. ML040120057

January 22, 2004 In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML040230175

February 3, 2004 In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML040340729

February 10, 2004 In a memorandum (signed by T. Liu), NRC summarized the December

11, 2003 and January 22, 2004 conference calls between the NRC staff

and SNC to discuss SNC's proposed responses to draft RAls concerning

the LRA. ML040410293

February 13, 2004 In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML040440296

February 13, 2004 In a memorandum (signed by T. Liu), NRC summarized the January 21,

22, and 23, 2004 conference calls between the NRC staff and SNC to

discuss draft RAls concerning the LRA. ML040440428

February 20, 2004 In a letter, NL-04-0069 (signed by L.M. stinson), SNC provided RAI

responses to the NRC. ML040570661

February 23, 2004 In a letter, NL-04-0264 (signed by L. M. Stinson), SNC notified NRC of

SNC's plans for withdrawal and analysis of standby capsules.

ML040560337

February 25, 2004 In a memorandum (signed by T. Liu), NRC summarized the January 28

and February 5, 2004 conference calls between the NRC staff and SNC

to discuss draft RAls concerning the LRA. ML040610023

February 26, 2004 In a memorandum (signed by T. Liu), NRC summarized the February 13,

17, and 18, 2004 conference calls between the NRC staff and SNC to

discuss draft RAls concerning the LRA. ML040580696

March 2, 2004 In a letter (signed by T. Liu), NRC provided SNC requests for additional

B-2
information concerning its review of the LRA. ML0406404940

March 5,2004

March 5, 2004

March 8, 2004

March 12,2004

March 12,2004

March 17, 2004

March 22, 2004

March 23, 2004

March 23, 2004

March 29,-2004

March 30, 2004

March 31, 2004

April 1, 2004

April 2, 2004

In a letter, NL-04-0372 (signed by L. M. Stinson), SNC provided NRC a

standby capsule withdrawal schedule. 'ML040690698

In a letter, NL-04-0318 (signed by L. M. Stinson), SNC provided a

response to NRC concerning RAls related to the staff's review of the

LRA. ML040710873'

In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. 'ML040680889

In a letter, NL-04-0383 (signed by L. M. Stinson), SNC provided a

response to' NRC concerning RAls related to the staff's review of the

LRA. ML040780586 I

In a memorandum (signed by T. Liu), NRC summarized the March 1, 2,

and 3, 2004 conference calls between the NRC staff and SNC to discuss

draft RAls concerning the LRA. -ML040750419

In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML040770911 7 -

In a letter (signed by T. Liu), NRC provided 'SNC requests for additional

information concerning its review of the LRA. ML040820914

In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML040830725

In a memorandum (signed by T.Liu), NRC summarized the February 18,

2004 conference call between the NRC staff and SNC to discuss draft

RAls concerning the LRA.'4 ML040830748

In a' letter (signed by T. Liu),` NRC pr6vided SNC requests for additional

-information concerning its revieii of the LRA. ML040890705

In a memorandum (signed by T. Liu), NRC summarized the March 10,

2004 conference call between the NRC staff and SNC to discuss draft

RAIs concerning the LRA.' ML040910027

In a letter, NL-04-0384 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML040970359.

In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML040920318

In a memorandum (signed by T. Liu), NRC summarized the March 22, 24

B-3
and 25, 2004 conference calls between the NRC staff and SNC to

discuss draft RAls concerning the LRA. ML040960134

April 7, 2004

April 8, 2004

April 12, 2004

April 16, 2004

April 21, 2004

April 22, 2004

April 22, 2004

April 22, 2004

April 29, 2004

April 29, 2004

May 5, 2004

May 10, 2004

In a letter, NL-04-0473 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML041050600

In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML041000295

In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML041040721

In a letter, NL-04-0617 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML041180569

In a memorandum (signed by T. Liu), NRC summarized the March 29, 30

and April 2, 2004 conference calls between the NRC staff and SNC to

discuss draft RAls concerning the LRA. ML041130097

In a letter, NL-04-0678 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML041190361

In a letter, NL-04-0654 (signed by L. M. Stinson), SNC provided

Westinghouse Technical Report WCAP - 12825 to NRC to supplement

RAIs related to the staff's review of the LRA. ML041190103

In a memorandum (signed by T. Liu), NRC summarized the April 7, 8 and

12, 2004 conference calls between the NRC staff and SNC to discuss

draft RAIs concerning the LRA. ML041170401

In a letter, NL-04-0715 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML041270481

In a report, "Audit and Review Plan for Plant Aging Management Reviews

and Programs, Joseph M.. Farley Nuclear, Plant, Units 1 and 2," NRC

outlined an audit and review plan for the aging management review and

aging management program related to the FNP LRA. ML042540243

In a letter, NL-04-0800 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML041350266

In a letter, NL-04-0831 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAIs related to the staff's review of the

B-4
-

LRA. 'ML041390518 -

May 17,2004 In a memorandum (signed by T. Liu), NRC summarized the April 21, 26

and 30, 2004 conference calls between the NRC staff and SNC to

discuss RAIs conceming the LRA. ML041380394

May 17,2004 In a letter (signed by T. Liu), NRC agreed to withhold information in

Westinghouse Technical R6port WCAP - 12825 concerning its review of

the LRA from publie'disclosure per request of SNC. ML041380426

May 26, 2004 In'a letter (signed by T. Liu),' NRC provided SNC a revised schedule for

the conduct of review for FNP. ML041470141

May 28, 2004 In a letter, NL-04-0924 (signed by.L. M. Stinson), SNC provided an Errata

'to their original application and responses to followup questions.

ML041560314 '"

June 2,2004 - In 'a memorandum'(signed by T. Liu), NRC summarized the March 15,

16,'17, and 18, 2004 conference calls between the NRC staff and SNC to

discuss RAls concerning the LRA. ML041540528

June 4, 2004 In a letter, NL-04-0933 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

;LRA. ML041670508.

June 10, 2004 In a letter (signed by T:Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML041620321

June 10,'2004 'Ina letter, NL-04-0967 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML041670393

June 18, 2004 In a letter, NL-04-1038 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML041740361

June 22, 2004 In a letter (signed by C.' Casto), NRC provided SNC Inspection Report

50-348/2004-007 and 50-364/2004-007 concerning its review of the LRA.

ML041750021 ' > -'-' -' - . -

June 25, 2004 A In a letter (signed by T. Liu); NRC provided SNC requests for additional

information concerning its review of the LRA. ML041890305

June 25,2004 ' -ia letter, NL-04-1096 (signed by L. M. Stinson), SNC provided

responses to NRC concerning RAls related to the staff's review of the

LRA. ML0411890305'**-

June 25, 2004 Iri'na memorandum (signed by T. Liu), NRC summarized the May 17, 20,

B-5
June 29, 2004

July 09, 2004

July 12, 2004

July 13, 2004

July 16, 2004

July 20, 2004

July 20, 2004

July 27, 2004

July 28, 2004

July 29, 2004

August 5, 2004

August 19,2004

August 25,2004

24, 26, and June 2, 4 and 7, 2004 conference calls between the NRC

staff and SNC to discuss RAls concerning the LRA. ML041800088

In a memorandum (signed by T. Liu), NRC summarized the June 3, 2004

meeting between the NRC staff and SNC to discuss RAls concerning the

LRA. ML041810407

In a letter, NL-04-1218 (signed by L. M. Stinson), SNC provided

responses to supplemental RAI information.- ML042010294

In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML041940416

In a memorandum (signed by T. Liu), NRC summarized the June 9,10,

21, 22, 23, 24, and July 6, 2004 conference calls between the NRC staff

and SNC to discuss RAls concerning the LRA. ML041950509

In a letter, NL-04-1296 (signed by L. M. Stinson), SNC provided

responses to supplemental RAI information. ML042100057

In a letter, NL-04-1021 (signed by L. M. Stinson), SNC provided an

annual application update to NRC. ML042160086

In a memorandum (signed by T. Liu), NRC summarized the July 6,12,

and 16, 2004 conference calls between the NRC staff and SNC to

discuss RAls concerning the LRA. ML042020601,

In a letter, NL-04-1267 (signed by L. M. Stinson), SNC provided

responses concerning RAls and the Future Action Commitment List to

NRC related to the staff's review of the LRA. ML042180163

In a letter (signed by T. Liu), NRC provided SNC requests for additional

information concerning its review of the LRA. ML042010294

In a memorandum (signed by T. Liu), NRC summarized the July 26,2004

conference calls between the NRC staff and SNC to discuss RAls

concerning the LRA. ML042110496

In a letter, NL-04-1396 (signed by L. M. Stinson), SNC provided

supplemental information for certain previously submitted RAI responses

related to the staff's review of the LRA. ML042260375

In a letter, NL-04-1486 (signed by L. M. Stinson), SNC provided

supplemental information for the review of the LRA. ML042390474

In a memorandum (signed by T. Liu), NRC summarized the August 3, 11,

and 13, 2004 conference calls between the NRC staff and SNC to

discuss questions pertaining to the LRA. ML042380469

B-6
-i- 1 n w . . . .

August 31, 2004

September 8, 2004

September 10, 2004

September 14, 2004

September 14, 2004

September 15, 2004

September 15, 2004

February 24, 2005

February 24, 2005

February 25, 2005

March 3, 2005

In a letter, NL-04-1594 (signed by L. M. Stinson), SNC provided

supplemental information for the review of the LRA. ML042530095

In an audit trip report (signed by D. Thatcher), NRC summarized the

scoping and screening methodology audit regarding the Southern

Nuclear Operating Company license renewal application for the Farley

Nuclear Plant, dated September 12, 2003. ML042520177

In an audit report, "Audit and Review Report for Plant Aging Management

Reviews and Programs, Joseph M. Farley Nuclear Plant, Units 1 and 2,"

NRC summarized it audit and review on aging management review and

aging management programs associated with the FNP LRA.

ML042540277

In a letter, NL-04-1781 (signed by L. M. Stinson), SNC provided revisions

to its Future Action Commitment List to NRC regarding its LRA.

ML042670363

In a letter (signed by T. Liu), NRC provided SNC a request for additional

information concerning its review of the LRA. ML042590013

In a memorandum (signed by T. Liu), NRC summarized the September

14,2004 conference call between the NRC staff and SNC to discuss an

RAI concerning the LRA. ML042590026

In a letter, NL-04-1801 (signed by L. M. Stinson), SNC provided response

to NRC concerning an RAI related to the staff's review of the LRA.

ML042670361

In a memorandum (signed by T. Liu), NRC summarized the February 24,

2005, conference call between the NRC staff and SNC to discuss a

followup question concerning the LRA. ML050550319

In a letter, NL-05-0340 (signed by L. M. Stinson), SNC provided response

to NRC concerning a followup question related to the staff's review of the

LRA. ML050630287

In a letter, NL-05-0366 (signed by L. M. Stinson), SNC provided a

revision to its Future Action Commitment List to NRC regarding its LRA.

ML050670393

In a letter, NL-05-0397 (signed by L. M. Stinson), SNC provided response

to NRC concerning a followup question related to the staff's review of the

LRA. ML050680166

B-7
APPENDIX C: REQUESTS FOR ADDITIONAL INFORMATION

I' , - : -,". -4 -,I ;j r7 ". ..,. , . I I . - -,. - 7< ,  -1 ,. " " - , - f.:. -, - A- 1.1,- 1, , " v -, " !" Z.- 0, :R) 1ssuahd&Dat&_5 -,,,; Resoohi&DateT.4,,',, .V . 1

,Section 1: Introdu tin eneral Discussion - : :

* * - e , -, a. nIa gv i ee- c, 

Section o-- : 2: Structures-and Contpounenjt Suect c to Aging Management Rev RAew'*-1 I . . . . . . - . . .I I . . .I. r . ....... .. . . . .. . . . 1

'-RAI 2.0-1 Ma 2, 004 March 31, 2004

RAI 2.0-2 -March 23, 2004 April 7, 2604

April 22, 2004,.,.

2.1 Scoping and Screening Methodology

RAI 2.1-1 December 12, 2003 - January 9, 2004

Supplemental Responses March 31, 2004

ApH116,2004

June 4, 2_b04

RAI 2.1-2 December 12, 2603 January 9, 2004

Supplemental Response March 31, 2004

2.2 Plant-Level Scoping Results

RAI 2.2-1 December 12, 2003 January 9, 2004

RAI 2.2-2 December 12, 2003 Jari6ay'b,'2004_

RAI 2.2-3 Decembe'r 12, 2003 January 9, 2004

RAI 2.2-4 -December 12, 2003 Januai 04-

RAI 2.2-5 . . . March 23, 2004 April 22, 2004

Supplemental Responses June 10, 2004

June 1 8,-2004

2.3'Scoping and Screening'Results wMechanical Systems

2.11'Reaictor Vessel,'Internalsl- and Reactor Coolant System

2.3.1 A Reactor Vessel

RAI 2.3.1.1-3 Feb 13, 2004 March 12, 2004

2.3.1.2 Reactor Ve sel Internals

RAI 2.3.1.2-1. Feb 13,2004 March 12,2004

2.3.1.3 Reactor System and Connected Lines_,..

..RAI 2.3.1.3-1 February 13, 2004 March 12,'2'004

.C-1
;\-q,.;;:RASE a G ssil,'dh d6nce' DAt Respnse'Dat~

2.3.1.4 Steam Generators

2.3.2 Engineered Safety Features

2.3.2.1 Containment Spray System

2.3.2.2 Containment Isolation System

2.3.2.3 Emergency Core Cooling System.

2.3.3 Auxiliary Systems

2.3.3.1 New Fuel Storage

2.3.3.2 Spent Fuel Storage

RAI 2.3.3.2-1 December 12, 2003 'January 9, 2004

RAI 2.3.3. 2-2 December 12, 2003 January 9, 2004

2.3.3.3 Spent Fuel Pool Cooling and Cleanup System -

2.3.3.4 Overhead Heavy and Refueling Load Handling System

RAI 2.3.3.4-1 March 23, 2004 April 7, 2004

RAI 2.3.3.4-2 March 23, 2004 April 7, 2004

2.3.3.5 Open Cycle Cooling Water System

RAI 2.3.3.5-1 March 23, 2004 April 22, 2004

2.3.3.6 Closed Cycle Cooling Water System '_ '_ _

RAI 2.3.3.6-1 March 23,2004 April 22, 2004

RAI 2.3.3.6-2 March 23, 2004 j April 22, 2004

2.3.3.7 Compressed Air

RAI 2.3.3.7-1 March 23, 2004 April22, 2004

RAI 2.3.3.7-2 March 23, 2004 April 22, 2004

RAI 2.3.3.7-3 - March 23, 2004 April 22, 2004

Supplemental .June Response 10, 2004

RAI 2.3.3.7-4 March 23, 2004 April 22, 2004

2.3.3.8 Chemical and Volume Control System

RAI 2.0-1 March 2, 2004 March 31, 2004

C-2
R A I c4 ssuance a'. 6-' sPonsbDateF'

2.3.3.9 Control Room Area Ventilation System

2.3.3.10 Auxiliary and Radwaste Area Ventilation System

2.3.3.11 Primary Containment Ventilation System - 7'

2.3.3.12 Yard Structures Ventilation System

2.3.3.13 Fire Protection ' _:_;__._-___-

RAI 2.3.3.13-1 March 23,-2004 April 7, 2004 -,

,RAI 2.3.3.13-2 ' March 23, 2004 -April 7, 2004

RAI 2.3.3.13-3 March 23,2004 - April 7,2004

2.3.3.14 Diesel Fuel Oil System '_-_._--

RAI 2.3.3.14-1 a i March 23, 2004 April 22, 2004

RAI 2.3.3.14-2 - ,, March 23, 2004 April22,2004

RAI 2.3.3.14-3 -- March 23, 2004 - April 22,'2004

- RA12.3.3.14-4 - - -- - March 23, 2004 'April 22,2004

2.3.3.15 Emergency Diesel Generator System -,

- RAt 2.3.3.15-1 -- March 23, 2004 April22,2004 -

- RAI 2.3.3.15-2 --- - --.- March 23,2004 April22,2004.

RAI 2.3.3.15-3 -- March 23,2004 'April 22,2004

, Supplemental Response June 10,2004;

RAI 2.3.3.15-4 - March 23, 2004 April 22, 2004

RAl 2.3.3.15-5 - ' ' - March 23, 2004 April 22,2004

_RA 2.3.3.15-6 March 23, 2004 April 22, 2004

.-RAI 2.3.3.15-7 March 23, 2004 April 22, 2004

2.3.3.16 Demineralized Water System

RAI 2.3.3.16-1 i - April 1, 2004 - April 29,2004

2.3.3.17 High Energy Line Break Dectection System , - -

RAI 2.3.3.17-1 - - March 23, 2004 April 22, 2004

2.3.3.18 Hydrogen Control System -

I

-C-3
.1

O't'41k elssuance Da&6." Responise;D , Date

2.3.3.19 Liquid Waste and Drains System

RAI 2.3.3.19-4 - April 1, 2004 April 29, 2004

2.3.3.20 Oil-Static Cable Pressurization System

RAI 2.3.3.20-1 December .12, 2003 January 9, 2004

RAI 2.3.3.20-2 December 12, 2003; January 9, 2004.

2.3.3.21 Potable and Sanitary Water System

RAI 2.3.3.21-1 March 23, 2004 April 7, 2004

2.3.3.22 Radiation Monitoring System

RAI 2.3.3.22-1 March 23, 2004 April 7, 2004

2.3.3.23 Reactor Makeup Water Storage System

RAI 2.3.3.23-1 - March 23, 2004 April 22, 2004

Supplemental Response June 18, 2004

RAI 2.3.3.23-2 March 23,2004-- April 22, 2004

RAI 2.3.3.23-3 March 23,2004 April 22,2004

2.3.3.24 Sampling System

RAI 2.3.3.24-1 March 23, 2004 April 22, 2004

2.3.4 Steam and Power Conversion System

2.3.4.1 Main Steam System

RAI 2.3.4.1-1 March 23, 2004 April 22, 2004

RAI 2.3.4.1-2 March 23, 2004 April22,2004

RAI 2.3.4.1-3 March 23, 2004 April 22,2004

2.3.4.2 Feedwater System

2.3.4.3 Steam Generator Blowdown System

RAI 2.3.4.3-1 March 23, 2004 April 22, 2004

2.3.4.4 Auxiliary Feedwater System -

RAI 2.3.4.4-1 |'March 23, 2004 |April 7, 2004

2.3.4.5 Auxiliary Steam and Condensate Recovery System -

C-4
R<7,§tt ~jltsuancwlDate.-; Rssc o11-seDate&

RAI 2.3.4.5-4 - April 1, 2004 April 29, 2004

2.3.4.6 Turbine and Turbine Auxiliaries:

RAI 2.3.4.6-1: April 1, 2004 April 29, 2004

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

Supports -

RAI 2.-1- February 13, 2004 March 12, 2004

RAI 2.4-2 February 13, 2004 March 12, 2004

-Supplemental Response . March 31, 2004

RAI 2.4-3 February 13, 2004 March 12; 2004

RAI 2.4-5 . February 13, 2004 March 12, 2004

RAI 2.4-7 March 2, 2004 March 31,2004

RAI 2.4-8 April 12, 2004 May 10, 2004

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control

Systems .-

RAI 2.5-1 - . March 29, 2004 April 29,'2004

.>K;.Section 3: Aging Maagem R eview t

RAI 3.01 March 17, 2004 April 16,2004

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

RAI 3.1_-1 February 3, 2004 March 5, 2004

RAI 3.1 .3.1.1-1 March 17, 2004 April 16, 2004

RAI 3.1.3.1.2-1 March 17, 2004 April 16, 2004

-RAI 3.1.3.2.1-1 - - March 17,2004 April 16,2004

RAI 3.1.2.4-1 March 22, 2004 April 22, 2004

RAI 31.2.4-2 March 22, 2004 April 22, 2004

RAI 3.1.2.4-3 March 22, 2004 April 22, 2004

RAI 3.1.2.4-4 March 22, 2004 April 22, 2004

-RA 3.1.2.4-5 March 22, 2004 April 22, 2004

RAI 3.1.2.4-6 March 22, 2004 April 22,- 2004

C-5
r I.

Date -- Respons Da 

RA 3.1-4 1 March 29,2004 April 29,2004

3.2 Aging Management of Engineered Safety Features'.!

RAI 3.2-2 February 3, 2004 March 5, 2004

RAI 3.2-3 February 3, 2004 March 5, 2004

RAI 3.2-4 February 3, 2004 - March 5, 2004

RAI 3.2-5 - February 3, 2004 - March 5, 2004

RAI 3.2-6 February 3, 2004 March 5, 2004

RAI 3.2-7 April 8, 2004 May 5, 2004

RAI 3.2-8 September 14, 2004 September 15, 2004

3.3 Aging Management of Auxiliary Systems

RAI 3.3-3 February 3, 2004 March 5, 2004

RAI 3.3-4 February 3, 2004 March 5, 2004

RAI 3.3-5 February 3, 2004 March 5, 2004

RAI 3.3-6 March 8, 2004 April 7, 2004

Supplemental Response May 28, 2004

RAI 3.3-7 March 8, 2004 April 7, 2004

RAI 3.3-8 March 8, 2004 April 7, 2004

RAI 3.3-9- March 8, 2004 April 7, 2004

RAI 3.3-10 March 8, 2004 April 7, 2004

RAI 3.3-11- March 8, 2004 April 7, 2004

Supplemental Response May 28, 2004

RAI 3.3-12 March 8, 2004 April 7, 2004

RAI 3.3-13 March 8, 2004 April 7, 2004

RAI 3.3-14 March 8, 2004 April 7, 2004

RAI 3.3-15 March 8, 2004 April 7, 2004

RAI 3.3-16 March 8, 2004 April 7, 2004

RAI 3.3-17 March 8, 2004 April 7, 2004

C-6
;e<.5 ,5Alt dW ,,9.3t~ stuaffWDatde 11|k -es'po'nseD

3.3.2.1.1 New Fuel Storage

3.3.2.1.2 Spent Fuel Storage (SFP)

3.3.2.1.3 SFP Cooling and Cleanup System - - *

3.3.2.1.4 Overhead Heavy anid Refueling Load Handling System

3.3.2.1.5 Open-Cycle Cooling Water System

RAI 3.3.2.1.5-1 . March 8, 2004 |April 7,,2004

3.3.2.1.6 Closed-Cycle Coolinrg Water System -

;3.3.2.1.7 Compressed Air System .. -

.RAI 3.3.2.1.7-1 March 8; 2004 April 7, 2004

3.3.2.1.8 Chemical and Volume Control System

RAI 3.3.2.1.8-1 ' March 8, 2004 -April 7,-2004--

RAI 3.3.2.1.8-2 ' March 8, 2004 April 7,-2004

3.3.2.1.9 Control Room Area Ventilation'System

RAI 3.3.2.1.9-1 I March 8, 2004 - April 7, 2004

3.3.2.1.10 Auxiliary and Radwaste Area Ventilation System

3.3.2.1.11 Primary Containment Ventilation System '

3.3.2.1.12 Yard Structures Ventilation System - - .

3.3.2.1.13 Fire Protection

3.3.2.1.14 Diesel Fuel Oil System

RAI 3.3.2.1.14-1 March 8, 2004' April 7, 2004

,RAI 3.3.2.1.14-2 - - , March 8, 2004 April 7,-2004-

3.3.2.1.15 Emergency Diesel Generator System ' ' ' .- - -

RAI 3.3.2.1.15-1 March 8, 2004 ' April 7, 2004

RAI 3.3.2.1.15-2 - March 8, 2004 April 7, 2004-

-Supplemental Response-. - -May 28, 2004

3.3.2.1.16 Demineralized Water System.

C-7
ssanR

3.3.2.1.17 High Energy Line Break Detection System

3.3.2.1.18 Hydrogen Control System

3.3.2.1.19 Liquid Waste and Drains

RAI 3.3.2.1.19-1 March 8, 2004 April 7, 2004

3.3.2.1.20 Oil-Static Cable Pressurization System

3.3.2.1.21 Potable and Sanitary Water System

RAI 3.3.2.1.21-1 March 8, 2004 |April 7, 2004

3.3.2.1.22 Radiation Monitoring System

3.3.2.1.23 Reactor Makeup Water Storage System

RAI 3.3.2.1.23-1 March 8, 2004 April 7,2004

3.3.2.1.24 Sampling System

RAI 3.3.2.1.24-1 March 8,2004 April 7, 2004

3.4 Aging Management of Steam and Power Conversion Systems .

RAI 3.4-1 February 3, 2004 March 5, 2004

Supplemental Response April 7, 2004

RAI 3.4-3 February 3, 2004 March 5, 2004

Supplemental Response . May 28, 2004

RAI 3.4-5 February 3, 2004 March 5, 2004

Supplemental Response April 7, 2004

RAI 3.4-6 February 3, 2004 March 5, 2004

RAI 3.4-7 - February 3, 2004 March 5, 2004

3.5 Aging Management of Containments, Structures, and Component Supports

RAI 3.5-1 February 3, 2004 March 5, 2004

RAI 3.5-2 February 3, 2004 March 5, 2004

RAI 3.5-4 February 3, 2004 March 5, 2004

RAI 3.5-5 February 3, 2004 March 5, 2004

RAI 3.5-7 February 3, 2004 March 5, 2004

RAI 3.5-8 February 3, 2004 March 5, 2004

C-8
II

.s~ RA IssuanceDat9 '~d~~~

RAI 3.5-9 _ - February 3,2004 March'5, 2004

RAI 3.5-12 March 22, 2004' 'April 22, 2004;

RAI 3.5-13 March 29, 2004 April 29, 2004

-RAI 3.5-14 March 29, 2004 April 29, 2004

RAI 3.5-15:_ June 10, 2004 June 25, 2004

RAI 3.5-16. _ _ June 10, 2004 June 25, 2004

3.6 Aging Management of Electrical Suppcrts " -

_RAI 3.6.2-1 .... _.M... A-2, 2004 March 31, 2004.

RAI 3.6.2-2. March 22, 2004 April 22, 2004

RAI 3.6.2-3 March 22, 2004 - April 22.2004

- -- RAI 3.6.2-4 - * - v March 22, 2004 Apri 22, 2004

Supplemental Response - - ; June 25,2004

RAI 3.6.2-5 March 22, 2004 April 22, 2004

RAI 3.6.2-6 March 22, 2004 April 22, 2004

Supplemental Response - . June 25, 2004

Sectin 4: TImei Limited A alysis

RAI 4.0-1 March 17, 2004 -April 16,2004

4.1 Identification of Time Limited Aging Analysis

4.2 Reactor Vessel Neutron Embrittlement

4.2.1 Neutron Fluence

RAI 4.2.1.3-1 - March 17, 2004 - April 16, 2004

4.2.2 Upper-Shelf Energy ; a, .

4.2.3 Pressurized Thermal Shock

-M- RAI 4.2.3.3-1 v March 17, 2004 April 16, 2004

4.2.4 Adjusted Reference Temperature' l

- RAI 4.2.4.2-1 March 17, 2004- April 16, 2004

RAI 4.2.4.3-1 i -: - March 17, 2004 April-16, 2004

C-9
iA s a X Resp ons ,Dab *tel

4.3 Metal Fatigue

4.3.1 Fatigue of ASME Class 1 Components

RAI 4.3.1-1 January 22, 2004 | February 20, 2004

RAI 4.3.1-2 January 22, 2004 February 20, 2004

RAI 4.3.1-3 January 22, 2004 February 20, 2004

RAI 4.3.1-4 January 22, 2004 February 20,:2004

4.3.2 Fatigue of Reactor Coolant Pump Flywheel

4.3.3 Fatigue of ASME Non-Class 1 Components

RAI 4.3.3-1 January 22, 2004 February 20, 2004

4.3.4 Containment Tendon Pre-Stress

RAI 4.3.4-1 J anuary 22, 2004 March 5, 2004

Supplemental Responses: - April16,2004

RAI 4.3.4-2-. January 22, 2004 March 5, 2004

4.3.5 Fatigue of Reactor Vessel Supports

4.4 Environmental Qualification of Electrical Equipment_

RAI 4.4-1 - March 2, 2004 March 31, 2004

4.5.1 Ultimate Heat Sink Silting Calculations

- RAI 4.5.1-1 March 17, 2004 April 16, 2004

4.5.2 Leak-Before-Break Analysis

RAI 4.5.2-1 April 1, 2004 April 29, 2004

RAI 4.5.2-2 April 1, 2004 April 22, 2004

I

I

4.5.3 Residual Heat Removal Relief Valve Capacity Verification Calculations (including

LTOP) - - I

-,: Appendix B Aging Management Programs and Activities!,.»ji2:.: ' 7

RAI B-i lMarch 17,2004 April 16, 2004

B.3.4 Rector Vessel Surveillance Program

RAI B.3.4-1 |TApril 12, 2004 | May 10, 2004

C-10
_ t1ssuance _ _ _ _ _ _ _ _ _ _ Ds' espncD atb 17i.

RAI B.3.4-2 April 12, 2004 May 10, 2004

B.3.5 Borated Water Leakage Assessment and Evaluation Program

RAI B.3.5-1 March 17,2004 |April 16,2004

RAI B.3.5-2 | March 17, 2004 IApril 16, 2004 II

B.5.1 Reactor Vessel Internals Program

RAI B.5.1-2 April 1, 2004 April 29,2004

RAI B.5.1-3 April 1, 2004 April 29, 2004

Supplemental Response June 25, 2004

RAI B.5.1-4 April 1, 2004 April 29,2004

B.5.2 Flux Detector Thimble Inspection Program

RAI B.5.2-1 March 17, 2004 April 16,2004

Supplemental Response August 5, 2004

RAI B.5.2-3 March 17, 2004 April 16,2004

Supplemental Response June 25, 2004

July 16, 2004

RAI B.5.2-4 March 17, 2004 April 16, 2004

RAI B.5.2-5 March 17, 2004 April 16, 2004

B.5.3 External Surfaces Monitoring Program

RAI B.5.3-1 [February 3, 2004 March 5,2004

B.5.8 NiCrFe Component Assessment Program

RAI B.5.8-1 March 29, 2004 April 29,2004

Supplemental Response I June 10, 2004

B.5.9 Periodic Surveillance and Preventive Maintenance Activities Program

RAI B.5.9-1 July 12, 2004 July 16, 2004

C-11
APPENDIXD: .1'PRINCIPAL CONTRIBUTORS

NAMr

.wgW.. RESPONSIBILITY

F. Akstulewicz

H. Ashar

G. Bagchi

S. Bailey

R. Barret

W. Bateman

S. Black

B. Boger

J. Calvo

T. Chan

K. Chang

D. Chen

P. Chen

S. Coffin

K. Cozens

K. Corp

D. Cummings

J. Cushing

R. Dennig

R. Dipert

N. Dudley

J. Fair

T. Ford

E. Forrest

G. Galletti

P. Garrity

F. Gillespie

D. Guha

J. Hannon

R. Hoefling

K. Hsu

E. Imbro

D. Jeng

R. Jenkins

S. Jones

C. Julian

P. Kuo

C. Lauron

B. Lee

S. Lee

M. Lemoncelli

C. Li

Y. Li

Management Oversight

Structural Engineering

Civil Engineering

Mechanical Engineering

Management Oversight

Management Oversight

Management Oversight

Management Oversight

Management Oversight

Management Oversight;

GALL Audit and Review

Technical Support

Mechanical Engineering

Management Oversight

GALL Audit

Technical Support

Legal Counsel

Environmental Project Management

Management Oversight

Plant Systems

Technical Support/Audit Team

Mechanical Engineering

Reactor Systems

Containment Systems

Quality Assurance

Technical Editing

Management Oversight

Technical Support

Management Oversight -

Legal Counsel

GALL Audit and Review

Management Oversight

Structural Engineering

Management Oversight

Plant Systems

Region II Inspection

Management Oversight

Materials Engineering -:

Technical Support

Management Oversight r -

Legal Counsel -

Plant Systems

Mechanical Engineering

D-1
M. Lintz

T. Liu

L. Lois

L. Lund

K. Manoly

D. Matthews

J. Medoff

M. Mitchell

J. Moore

R. Moore

G. Morris

K. Naidu

D. Nguyen

R. Pettis

R. Pichumani

J. Pulsipher

T. Quay

M. Scott

W. Scott

P. Shemanski

D. Shum

D. Solorio

T. Steingass

J. Stmisha

A. Stubbs

J. Tappert

D. Terao

J. Terrell

D. Thatcher

J. Uhle

K. Van Doom

A. Walker

S. Weerakkody

R. Wescott

J. Wermiel

S. West

L. Whitney

J. Yerokun

R. Young

GALL Audit

Project Manager

Reactor Systems

Management Oversight

Management Oversight

Management Oversight

Materials Engineering

Management Oversight

Legal Counsel

Region 11 Inspection

Electrical Engineering

Quality Assurance

Electrical Engineering

Quality Assurance

Civil Engineering

Containment Systems

Management Oversight

Region 11 Inspection

Quality Assurance

Electrical Engineering

Plant Systems

Management Oversight

Materials Engineering

Mechanical Engineering

Plant Systems

Management Oversight

Management Oversight

Materials Engineering

Management Oversight

Management Oversight

Region 11 Inspection

Administrative Support

Management Oversight

Civil Engineering

Management Oversight

Management Oversight

Plant Systems

Management Oversight

Plant Systems

CONTRACTORS

CONTRACTOR TECHNICAL AREA

H. Abelson, Information Systems Laboratories (ISL)

C. Amoruso, ISL

R. Chhina, ISL

K. Dungan, ISL

Plant Systems

Administrative Support

GALL Audit

Plant Systems

D-2
S. Faridi, ISL

B. Gitnick, ISL

K. Green, ISL

C. Hofmayor, Brookhaven National Laboratory (BNL)

R. Morante, BNL

S. Newberry, ISL

E. Patel, ISL

S. Pope, ISL

F. Saba, ISL

S. Tam, Argonne National Laboratory

Plant Systems

GALL Audit/Plant Systems

Plant Systems

Containment Systems

Containment Systems

Contractor Management Oversight

GALL Audit

GALL Audit

GALL Audit/Plant Systems

Mechanical Engineering

D-3
APPENDIX-E.- 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 Farley Nuclear Plant,

Units 1 and 2, Docket Numbers 50-348 and 50-364, respectively. '

American Society of Mechanical Engineers (ASME)-

ASME Boiler and Pressure Vessel Code, Section II, Subsection NB, Class 1 Components.

ASME Boiler and Pressure Vessel Code, Section III, Subsection NG, Core Support Structures.

ASME Boiler and Pressure Vessel Code, Section 1I1, Class 2 and 3 Piping Failures. -

ASME Boiler and Pressure Vessel Code, Section6 lll,'Subsection ND,'Class 3 Rules for

Construction of Nuclear Power Plant Components.,

ASME Boiler and Pressure Vessel Code, Section Xl, Rules for Inservice Inspection of Nuclear

Power Plant Components, 1992 Edition.

ASME Boiler and Pressure Vessel Code, Section Xl, Rules for Inservice Inspection of Nuclear

Power Plant Components, 1989 Edition.

ASME Boiler and Pressure Vessel Code, Section Xl, Subsection IWB, Requirements for

Class 1 Components of Light-Water Cooled Power'Plants.

ASME Boiler and Pressure Vessel Code, Section Xl, Subsection IWC, Requirements for

Class 2 Components of Light-Water Cooled Power Plants.

ASME Boiler and Pressure Vessel Code, Section Xl, Subsection IWE, Requirements forClass

MC and Metallic Liners of Class CC Components'of Light-Water Cooled Power Plants.

ASME Boiler and Pressure Vessel Code, Section Xl, Subsection IWF,' Requirements for Class

1, 2, 3, and MC Component Supports of Light Water Cooled Plants.

ASME Boiler and Pressure Vessel Code, Section XI, Appendix G, Fracture Toughness Criteria

for Protection Against Failure.'

ASME Boiler and Pressure Vessel Code, 'Code Case N-481, Altemative' Examination

Requirements for Cast Austenitic Pump Casings, Section Xl, Division 1.'

ANSI B30.16, Overhead Hoists (Under:,' American National Standard

ANSI B30.2.0, Overhead and Gantry Cranes, Section 2-2, Safety.Standards for Cableways,

Cranes, Derricks, Hoists, Hooks, Jacks, and Slin gs,American National Stan'dard.

American Society for Testing and Materials (ASTM) Procedures

E-1
ASTM Designation El 85-82, Standard Practice for Conducting Surveillance Tests for LightWater Cooled Nuclear Power Reactor Vessels, 1982

Department of Energy National Laboratories

Sandia Contractor Report SAND96-0344, Aging Management Guideline for Commercial

Nuclear Power Plants - Electrical Cable and Terminations, Prepared by Ogden Environmental

and Energy Services, Inc., printed September 1996.

SAND 93-7069, Aging Management Guideline for Commercial Nuclear Power Plants - Motor

Control Centers, February 1994.

SAND 93-7027, Aging Management Guideline for Commercial Nuclear Power Plant - Electrical

Switchgear.

Electric Power Research Institute (EPRI) and Materials Reliability Program (MRP)

EPRI Report TR-1 05714, Volumes 1, Revision 4, and Volume 2, Revision 4 PWR Primary

Water Chemistry Guidelines, March 1999.

EPRI Report TR-1 02134, Revision 5, PWR Secondary Water Chemistry Guidelines,

May 2000.

EPRI-TR-1 04213, Bolted Joint Maintenance and Application Guide, December 1995.

EPRI Report TR 107621, Revision 1, Steam Generator Integrity Assessment Guidelines,

March 2000.

EPRI Report NSAC-202L, Revision 2, Recommendations for an Effective Flow Accelerated

Corrosion Program, April 1999.

EPRI Report TR-103834-P1-2, Effects of Moisture on the Life of Power Plant Cables, Part 1:

Medium-Voltage Cables, Part 2: Low-Voltage Cables, prepared by Ogden Environmental and

Energy Services Company, Final Report, August 1994

EPRI Report TR-1 003057, License Renewal Electrical Handbook, December 2001.

EPRI Report TR-1 07396, Closed Cooling Water Chemistry Guidelines, October 1997.

EPRI Report TR-1 09619, Guideline for the Management of Adverse Localized Equipment

Environments, June 1999.

EPRI Report TR-1 003083, Materials Reliability Program Guidelines for Addressing Fatigue

Environmental Effects in a License RenewalApplication (MRP-47), October 2001.

MRP Topical Report TP-1 001 491, Part 2, PWR Materials Reliability Program Interim Alloy 600

Safety Assessment for US Power Plants (MRP-44), May 2001.

E-2
Miscellaneous

Aging and Life Extension of Major Light Water Reactor Components, edited by V.N. Shah and

P.E. MacDonald, 1993, Elsevier Science Publishers.

American Concrete Institute, ACI 349.3, Evaluati6n of Existing Nuclear Safety-Related

Concrete Structures.

American Concrete Institute, ACI 224.1, Causes, Evaluation, and Repairs of Cracks in Concrete

Structures.

American Concrete Institute, ACI 201.1, Guide for Making a Condition Survey of Concrete in

Service.

Letter frorm E. A. Reeves, Senior Project Manager, U.S. Nuclear Regulatory Commission, to W.

G.' Hairston, III, Senior Vice President, Alabamna Power Company, Audit of Actions Relating to

NRC Bulletin 88-09, Thimble Tube Thinning in Westinghouse Reactors,"for Joseph M. Farley

Nuclear Plant, Units 1 and2 (TAC Nos. 72659 and 72669), January 12, 1990.

NRC SECY 96-080, Issuance of Final AmendMent to 10 CFR 50.55a to incorporate by:

reference the ASME Boiler and Pressure Vessel Code (ASME CODE), Section Xi, Division 1,-

Subsection IWE and Subsection IWL, April 17, 1996.

NRC Inspection Procedure 62002, Inspection of Structure, Passive Components, and Civil

Engineering Features at Power Plants, December 1996.

Westinghouse Electric Company Letter No.'ALA-03-7 [from J. L. Tain, Westinghouse Electric

Company Managerfor'Southern Nuclear Projects, to J. B. Beasley,'Jr., Vice-President Farley.

Project, Southern Nuclear Operating Company], Southern Nuclear Operating Company, Joseph

M. Farley Nuclear Plant, Unit 2, Flux Thimble Eddy Current Data Evaluation for Cycle 15,

February 4, 2003.. ' ;.

National Fire Codes 1979

National Fire Protection Association (NFPA-20), Standard for Installation of Centrifugal Fire

Pumps, June 1978. ' -

National Fire Protection Association (NFPA-25), Standard for the Inspection, Testing, and

Maintenance of Water-Based Fire Protection Systems, 1998.

Nuclear Energy Institute (NEI) ' -

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

54 - The License Renevwal Rule, Nuclear Energy Institute,' March 2001.

NEI 97-06, Steam Generator Progrdrn Guidefiries&1 997.

NEI 96-03, Industry Guideline for Monitoring Structures.

E-3
Nuclear Management and Resources Council (NUMARC)

Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light

Water Reactors, NUMARC Report Number 87-00, November 1987.

Pressurized Water Reactor Containment Structures License Renewal Industry Report,

NUMARC Report Number 90-01, Nuclear Management and Resources Council, Revision 1,

September 1991.

Class I Structures License Renewal Industry Report, NUMARC Report Number 90-06, Nuclear

Management and Resources Council, Revision 1, December 1991.

Southern Company/Alabama Power Correspondence

Alabama Power Company Letter 1 OCFR50.54 from R. P. McDonald, Senior Vice President, to

the NRC Document Control Desk, Joseph M. Farley Nuclear Plant - Units 1 & 2, Response to

NRC Generic Letter 88-05, May 31, 1988

Alabama Power Letter [W.G. Harrison, l1l, Senior Vice President - Nuclear Operations] to the

NRC Document Control Desk, Joseph M. Farley Nuclear Plant - Units I and 2, Thimble Tube

Thinning in Westinghouse Reactors, NRC Bulletin 88-09, November 2, 1988

SNC Serial Letter NEL-02-0068, Joseph M. Farley Nuclear Plant, 15-Day Response to NRC

Bulletin 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure

Boundary Integrity, March 29, 2002

SNC Serial Letter NEL-02-0113, Joseph M. Farley Nuclear Plant, 60-Day Response to NRC

Bulletin 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure

Boundary Integrity, May 16, 2002

SNC Serial Letter NL-03-0088, Joseph M. Farley Nuclear Plant, Votgle Electric Generating

Plant, Response to NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and

Reactor Coolant Pressure Boundary Integrity," 60-Day Response, Request for Additional

Information, January 17, 2003

SNC Serial Letter NL-03-0390, Joseph M. Farley Nuclear Plant, Votgle Electric Generating

Plant, Answer to Order Establishing Interim Inspection Requirements for Reactor Pressure

Vessel Heads at Pressurized Water Reactors, March 3, 2003

SNC Serial Letter NL-03-0815, Joseph M. Farley Nuclear Plant, Responses to NRC Questions

on Relaxation Request to Order EA-003-09, April 11, 2003

SNC Serial Letter NL-03-0865, Joseph M. Farley Nuclear Plant - Unit 1, Supplemental

Information for Relaxation Request to Order EA-003-09, April 18, 2003

SNC Serial Letter NL-03-1387, Joseph M. Farley Nuclear Plant - Unit 1, Results of Reactor

Pressure Vessel Head Inspections Required by Order EA-003-09, June 30, 2003

E-4
SNC Serial Letter NL-03-1958, Joseph M. Farley Nuclear Plant, .Votgle Electric Generating

Plant, Response to NRC Bulletin 2003-02, "Leakage From Reactor Pressure Vessel Lower

Head Penetrations and Reactor Coolant Pressure Boun'dary Integrity,". September -19,2003 -

SNC Serial Letter NL-04-0264, Joseph'M.' Farley Nuclear Plant, Reactor Material Surveillance

Program, Standby Specimen Capsule Withdrawal Plans, February 23, 2004

SNC Serial Letter NL-04-0610 to the NRC Document Control Desk, Joseph M. Farley Nuclear.

Plant - Unit 1, Reactor Vessel Surveillance Capsule Results, April 16, 2004

US Nuclear Regulatory Commission (NRC)

Audit Reports

Audit and Review Plan for Plant Aging Management Reviews and Programs, Joseph M. Farley.

Nuclear Plant, Units I and 2, April 29, 2004 (ML042540243).

*n -~ - , - . i r- -. , .. ;..;

Audit Trip Report Regarding the Southern Nuclear Operating Company License Renewal -

Application for the Farley Nuclear Plant, Dated September 12, 2003, September 8, 2004

(ML042520177). -

Audit and Review Report for Plant Aging Management Reviews and Programs, Joseph M. - --

Farley Nuclear Plant, Units 1 and 2, September 10, 2004 (ML042540277).

Bulletins (BL)

BL 82-02, Degradation of Threaded Fasteners in the Reactor Coolant Pressure Boundary of

PWR Plants, June 2,1982.

BL 88-09, Thimble Tube Thinning in Westinghouse Reactors, July 26,1988

BL 88-11, Pressurizer Surge Line Thermal Statification, December 20, 1988.

BL 2001-01, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles,

August 3, 2001. a - 2 ',', '

BL 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure

Boundary Integrity, March 18, 2002. -

: ':: ;.I'

BL 2002-02, Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle Inspection

Progra's, August 9, 2002.:- - --- - . . -- -. -

BL 2003-02, Leakage From Reactor Pressure Vessel Lower Head Penetrations and Reactor

Coolant Pressure Boundary lntegrity, August21,;2003 -

BL 2004-01 ,-Anspection-of Alloy 8211821600 Materials Used in the Fabrication of Pressurizer

Penetrations and Steam Space Piping Connections at Pressurized-Water Reactors,-

May 28, 2004

E-5
Code of Federal Regulations (10 CFR)

10 CFR 50.36, Technical Specifications, U.S. Nuclear Regulatory Commission.

10 CFR 50.48, Fire Protection, U.S. Nuclear Regulatory Commission.

10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for

Nuclear Power Plants, U.S. Nuclear Regulatory Commission.

10 CFR 50.55a, Codes and Standards, U.S. Nuclear Regulatory Commission.

10 CFR 50.59, Changes, Tests, and Experiments, U.S. Nuclear Regulatory Commission.

10 CFR 50.60, Acceptance Criteria for Fracture Prevention Measures for Lightwater Nuclear

Power Reactors for Normal Operations, U.S. Nuclear Regulatory Commission.

10 CFR 50.61, Fracture Toughness Requirements for Protection Against Pressurized Thermal

Shock Events, U.S. 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, U.S. Nuclear Regulatory

Commission.

10 CFR 50.63, Loss of All Altemating Current Power, U.S. Nuclear Regulatory Commission

10 CFR 50.90, Application for Amendment of License or Construction Permit, U.S. Nuclear

Regulatory Commission.

10 CFR 50 Domestic Licensing of Production and Utilization Facilities, U.S. Nuclear Regulatory

Commission.

10 CFR Part 50, Appendix G, Fracture Toughness Requirements, U.S. Nuclear Regulatory

Commission.

10 CFR Part 50, Appendix H, Reactor Vessel Material Surveillance Program Requirements,

U.S. Nuclear Regulatory Commission.

10 CFR Part 51, Environmental Protection Regulation for Domestic Licensing and Related

Regulatory Functions, U.S. Nuclear Regulatory Commission.

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

U.S. Nuclear Regulatory Commission.

10 CFR 100, Reactor Site Criteria, U.S. Nuclear Regulatory Commission.

10 CFR Part 100, Appendix A, Seismic and Geological Siting Criteria for Nuclear Power Plants,

U.S. Nuclear Regulatory Commission.

E-6
29 CFR Chapter XVII, 1910.179, Overhead and 'Gantry Cranes, Occupational Safety and

Health Administration. ., . . , b l%. .n

Correspondence

Letter from C. l. Grimes (NRC) to D. J. Walters (NEI), License Renewal Issue No. 98-0030,

Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Components, May 19, 2000.

Letter from W. T. Russell (NRC) to W. Rasin (NUMARC, [NEl)), Safety Evaluation for Potential

Reactor Vessel Head Adaptor Tube Cracking, November 19,1993.

Letter from C. l. Grimes (NRC) to D. J. Walters (NEI), License Renewal Issue No. 98-0012,

Consumables, April 20,1999.

Letter from John -. Nakoski, Chief,- Section 1 Project Directorate 2, Division of Licensing and

Project Management, Office of Nuclear Reactor Regulation, to M. L. Stinson, Vice President, -

Southern Nuclear Operating Company, Joseph M. Farley Nuclear Plant, Units 1 and 2, RE:

Specimen Capsule Withdrawal Revisiohs (TAC Nos. MC2270 and MC2271), May 15,2004

Letter from E. A. Reeves, Senior Project Manager, U.S. Nuclear Regulatory Commission, to W.

G. Hairston, ll, Senior Vice President, Alabama Power Company, Audit of Actions Relating to

NRC Bulletin 88-09, 'Thimble Tube Thinning in Westinghouse Reactors," for Joseph M. Farley

Nuclear Plant, Units 1 and 2 (TAC Nos. 72659 and 72669), January 12, 1990

* , ,, - *.

Generic Letters (GL)

GL 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components In

PWR Plants, March 17, 1988.

GL 92-01, Revision 1, Supplement 1, Reactor Vessel Structural Integrity, May 18, 1995.

GL 96-03, Relocation of the Pressure'Temperature'Limit Curves and Low Temperature

Overpressure Protection System Limits, January 31 1996

* GL 97-01, Degradation of Control Rod Drive'Mechanism Nozzle and Other Vessel Closure

Head Penetrations, April 1, 1997.

GL 97-06, Degradation of Steam Generator Intemals, December 30,1997..

GL 89-13, 'Service Water System Problems Affecting Safety-Related Equipment, July 18, 1989.

GL 96-04, Boraflex Degradation in Spent Fuel Pool Storage Racks, June 26,1996.

Information Notices (IN)

IN 87-44, Thimble Tube Thinning in Westinghouse Reactors, September 16,1987.

IN 2001-05,: Through-Wall Circumferential Cracking of Reactor Pressure Vessel Head Control

E-7
Rod Drive Mechanism Penetration Nozzles at Oconee Nuclear Station, Unit 3, April 30, 2001.

IN 87-49, Deficiencies in Outside Containment Flooding Protection, October 9, 1987.

IN 97-45, Supplement 1:Environmental Qualification Deficiency for Cables and Containment

Penetration Pigtails, February 17, 1998.

Inspection Reports

J. M. Farley Nuclear Plant - Inspection Report 50-348/2004-007, 50-364/2004-007, June 22, -

2004.

Orders

EA-003-09, Issuance of Order Establishing Interim Inspection Requirements for Reactor

Pressure Vessel Heads at Pressurized Water Reactors, February 11, 2003

EA-003-09, The First Revised NRC Order EA-03-009, February 20, 2004

Regulatory Guides (RG)

RG 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components, May 1973.

RG 1.44, Control of the Use of Sensitized Stainless Steel, May 1973.

RG 1.45, Reactor Coolant Pressure Boundary Leakage Detection Systems, May 1973.

RG 1.52, Design Testing and Maintenance Criteria for Post Accident Engineered-SafetyFeature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled

Nuclear Power Plants, July -1978.

RG 1.89, Revision 1, Environmental Qualification of Certain Electrical Equipment Important to

Safety for Nuclear Power Plant, June 1984.

RG 1.99, Revision 2, Radiation Embrittlement of Reactor Pressure Vessel Materials, May.1 988.

RG 1.127, Revision 1, Inspection of Water Control Structures Associated with Nuclear Power

Plants, March 1978.

RG 1.147, Revision 12, Inservice Inspection Code Case Acceptability, ASME Section XI,

Division 1, May 1999.

RG 1.155, Station Blackout, August 1988.

RG 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2,

March 1997.

RG 1.163, Performance-Based Containment Leak-Test Program, September 1995.

E-8
RG 1.188, Standard Format and Content forApplications to Renew Nuclear Power Plant

Operating Licenses, July 2001.

RG 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron

Fluence, March 2001.

Regulatory Information Summaries (RIS). .

RIS 2003-013, NRC Review of Responses to Bulletin 2002-01, "Reactor Pressure Vessel Head

Degradation and Reactor Coolant Pressure Boundary Integrity," July 29, 2003.

Technical Reports

NUREG-1 339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear

Power Plants, June 2003

NUREG/CR-1437, Supplement 18, Generic Environmental Impact Statement for License

Renewal of NuclearPlants Regarding Joseph M.-Farley.NuclearPlant, Units 1 and 2,.Draft

Report for Comment, August 2004.

NUREG/CR-1 557, Summary of Technical Information and Agreements From Nuclear:,

Management and Resources Council Industry Reports Addressing License Renewal, October

1996.

NUREG-1 611, Aging Management of Nuclear Power Plant Containments for License Renewal,

September 1997.

NUREGICR-1723, Safety Evaluation Report Related to the License Renewal of Oconee

Nuclear Station, Unit 1, 2 and 3, March 2000.

NUREGICR-1739, Analysis of Public Comment on the Improved License Renewal Guidance

Documents, July 2001.

NUREG-1760, Aging Assessment of Safety-Related Fuses Used in Low- and Medium-Voltage

Applications in Nuclear Power Plants, May 2002.

NUREG/CR-1800, Standard Review Plan for Review of License RenewalApplications for

Nuclear Power Plants, July 2001.

NUREG/CR-1 801, Generic Aging Lessons Learned (GALL) Report, July 2001.

NUREG/CR-4715,-An Aging Assessment of Relay and Circuit Breakers and System

Interactions, June 1987. -

NUREG/CR-5576, Survey of Boric Acid Corrosion of Carbon Steel Components in Nuclear

Plants, June 1990.

NUREG/CR-5704, Curves of Austenitic Stainless Steel, April 1999.

E-9
NUREG/CR-6048, Pressurized-Water Reactor Internals Aging Degradation Study,

September 1993.

NUREG/CR-6260, Application of NUREG/CR 5999 Interim Fatigue Curves to Selected Nuclear

Power Plant Components, March 1995.

NUREG/CR-6583, Effects of LWR Coolant Environment on Fatigue Design Curves of Carbon

and Low Alloy Steel, March 1998.

NUREG/CR-6679, Assessment of Age-Related Degradation of Structures and Passive

Components for U.S. Nuclear Power Plants, August 2000.

NUREG/CR-6754, Review of Industry Responses to NRC Generic Letter 97-06 on Degradation

of Steam Generator Intemals, December 2001.

Westinghouse Topical Reports (WCAP)

WCAP-8810, Southern Alabama Power Company, Joseph M. Farley Unit 1, Reactor Vessel

Radiation Surveillance Program, December 1976

WCAP-8956, Alabama Power Company, Joseph M. Farley Unit 2, Reactor Vessel Radiation

Surveillance Program, August 1977

WCAP-9717, Analysis of Capsule Yfrom the Alabama Power Company, Joseph M. Farley Unit

1, Reactor Vessel Radiation Surveillance Program, June 1980

WCAP-1 0425, Analysis of Capsule U from the Alabama Power Company, Joseph M. Farley

Unit 2, Reactor Vessel Radiation Surveillance Program, October 1983

WCAP-1 0456, The Effects of Thermal Aging on Structural Integrity of Cast Stainless Steel

Piping for Westinghouse Nuclear Steam Supply Systems, November 1983

WCAP-1 0474, Analysis of Capsule U from the Alabama Power Company, Joseph M. Farley

Unit 1, Reactor Vessel Radiation Surveillance Program, February 1984

WCAP-1 1438, Analysis of Capsule Wfrom the Alabama Power Company, Joseph M. Farley

Unit 2, Reactor Vessel Radiation Surveillance Program, April 1987

WCAP-1 1563, Analysis of Capsule X from the Alabama Power Company, Joseph M. Farley

Unit 1, Reactor Vessel Radiati6n Surveillance Program, September 1987

WCAP-1 2471, Analysis of Capsule X from the Alabama Power Company, Joseph M. Farley

Unit Z Reactor Vessel Radiation Surveillance Program, December 1989

WCAP-1 2866, Bottom Mounted Instrumentation Flux Thimble Wear, 1991

WCAP-14040-NP-A, Rev. 2, Methodology used to Develop Cold Overpressure Mitigating

System Setpoints and RCS Heatup and Cooldown Limit Curves, January 1996.

E-10
WCAP-14196, Analysis of Capsule Wfrom the&Alabarna Power Company, Joseph'M. Farley

Unit 1, Reactor Vessel Radiation Surv6illah6e Program;, Februa'ry 1995

WCAP-'14422, Revision'2-A',Licdnse RenewalEValuation: AgingManagemertforReactor

Coolant Systeri Supports, Westinghouse General.Technical Report, December 2000 - -

WCAP-14535A, Topical Rep6rt on Reactor Coolant Pump Flywheel Inspection Elimination,'

November 1996

WCAP-1 4574-A, License-Renewal Evaluation: Aging Management Evaluation for Pressurizers,

December 2000

WCAP-1 4575-A, License Renewal Evaluation: Aging Management Evaluation for Class 1:

Piping and Associated Pressure Boundary Components, December 2000

WCAP-14577, Reviisi6n 1-A, License Renewal Evaluation: Aging Management for Reactor

Internals, October2000 -

WCAP-1 4574-A, License Renewal Application: Aging Management Evaluation for.,

Pressurizers, December 2000

WCAP-14575-A, Aging Management Evaluation for Class I Piping and Associated Pressure

Boundary Components, August 1996

WCAP-14577, Revision 1-A, License Renewal Application: Aging Management Evaluation for

Reactor Internals, March 2001

WCAP-14687, Joseph M. Farley Units 1 and 2 Radiation Analysis and Neutron Dosimetry

Evaluation, June 1996

WCAP-1 4689, Rev. 6, Farley Units 1 and 2 Heatup and Cooldown Limit Curves for Normal

Operation and PTLR Support Documentation, April 2001.

WCAP-14901, Revision 0, Background and Methodology for Evaluation of Reactor Vessel

Closure Head Penetration Integrity for the Westinghouse Owners Group, July 1997

WCAP-1 5171, Analysis of Capsule Z from the Alabama Power Company Joseph M. Farley

Nuclear Plant Unit 2 Reactor Vessel Radiation Surveillance Program, February 1999.

WCAP-1 6221 -NP, Rev. 0, Analysis of Capsule V from the Southern Nuclear Operating

Company, Joseph M. Farley Unit I Radiation Surveillance Program, March 2003.

Other Westinghouse Electric Company Correspondence

Westinghouse Electric Company Letter No. ALA-03-7 [from J. L. Tain, Westinghouse Electric

Company Manager for Southern Nuclear Projects, to J. B. Beasley, Jr., Vice President Farley

Project, Southern Nuclear Operating Company], Southern Nuclear Operating Company, Joseph

M. Fardey Nuclear Plant, Unit 2, Flux Thimble Eddy Current Data Evaluation for Cycle 15,

February 4, 2003.

-E-11
WCAP-1 4689, Rev. 6, Farley Units 1 and 2 Heatup and Cooldown Limit Curves for Normal

Operation and PTLR Support Documentation, April 2001.

WCAP-1 4901, Revision 0, Background and Methodology for Evaluation of Reactor Vessel

Closure Head Penetration Integrity for the Westinghouse Owners Group, July 1997

WCAP-1 5171, Analysis of Capsule Z from the Alabama Power Company Joseph M. Farley

Nuclear Plant Unit 2 Reactor Vessel Radiation Surveillance Program, February 1999.

WCAP-1 6221 -NP, Rev. 0, Analysis of Capsule V from the Southem Nuclear Operating

Company, Joseph M. Farley Unit 1 Radiation Surveillance Program, March 2003.

Other Westinghouse Electric Company Correspondence

Westinghouse Electric Company Letter No. ALA-03-7 [from J. L. Tain, Westinghouse Electric

Company Manager for Southern Nuclear Projects, to J. B. Beasley, Jr.,, Vice President Farley

Project, Southern Nuclear Operating Company], Southern Nuclear Operating Company, Joseph

M. Farley Nuclear Plant, Unit 2, Flux Thimble Eddy Current Data Evaluation for Cycle 15,

February 4, 2003

E-1 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, If any.)

BIBLIOGRAPHIC DATA SHEET

(see lnsfructons on the reverse) NUREG- "825

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Safety Evaluation Report MONTH YEAR

Related to the License Renewal of the

Joseph M. Farley Nuclear Plant, Units I and 2 May 2005

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Tilda Liu . Final

7. PERIOD COVERED (Inclusive Dates)

9/15/2003 - 4/15/2005

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (IfNRC. provide Division. Office orRegion. US. NucjearRegulatory Cmnmission. and maihlg address; icontractor.

provide name and madling address.)

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type 'Sanme as above; if contractor, provide NRC Division. Office or Region, U.S. Nudear Regulatory Conmmission.

and mailing address.)

Same as item no. 8 above

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 words or less)

This safety evaluation report (SER) documents the technical review of the Joseph M. Farley Nuclear Plant (FNP), Units 1

and 2. license renewal application (LRA) by the staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff). By letter

dated September 12, 2003, Southern Nuclear Operating Company, Inc. (SNC or the applicant) submitted the LRA for FNP in

accordance with Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part54). The SNC is requesting renewal of the

operating licenses for FNP, Units I and 2 (Facility Operating License Numbers NPF-2 and NPF-8, respectively) for a period of

20 years beyond the current expiration dates of midnight, June 25, 2017, for Unit 1 and midnight, March 31,2021, for Unit 2.

The FNP units are located about 16.5 miles east of the City of Dothan, in Houston County, Alabama, on the west bank of

the Chattahoochee River. The NRC issued the construction permits for FNP, Units 1 and 2, on August 16, 1972. The

operating licenses were issued by the NRC on June 25, 1977, for Unit 1 and March 31, 1981, for Unit 2. The FNP consists of

two Westinghouse pressurized-water reactor units. Each unit is designed to generate 2775 megawatt thermal (MWt), or

approximately 910 megawatt electric (MWe).

The staff reviewed the FNP 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 staffs

conclusion of its review of the FNP LRA can be found in Section 6 of this SER.

The NRC license renewal project manager is Ms. Tilda Liu. Ms. Liu may be reached at (301) 415-1315. Written

correspondence should be addressed to the Ucense Renewal and Environmental Impacts Program, Mail Stop 0-11 F1, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001.

12. KEY WORDSIDESCRIPTORS (List words orphrases that wiff assist researchers hi fxafing the report.) 13. AVAILABILITY STATEMENT

10 CFR 54, license renewal, license renewal application, Farley, scoping and screening, aging unlimited

management, aging management program, aging management review, time limited aging analysis, 14. SECURITY CLASSIFICATION

safety evalutation report, Docket Number 50-348, Docket Number 50-364, Southem Nuclear Operating rThisPage)

Company unclassified

(TMis Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (9-2004) PRINTED ON RECYCLED PAPER
Federal Recycling Program
UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

OFFICIAL BUSINESS